California Electric Rule 21: Fast Track Screens, Fees, and Timelines

If you’re connecting solar panels or battery storage to the grid in PG&E, SCE, or SDG&E territory, the California Electric Rule 21 interconnection requirements set the technical standards your equipment must meet, the application and screening process your project goes through, the fees you pay, and the timeline before you can legally switch the system on.1California Public Utilities Commission. Electric Rule 21 – Generating Facility Interconnections The tariff is administered by the California Public Utilities Commission and applies uniformly across the three investor-owned utilities.

Who Rule 21 Applies To

Rule 21 covers customers of Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric. A 5-kilowatt rooftop array and a multi-megawatt commercial battery system go through the same tariff framework, though the review path scales with size and complexity. Municipal utilities such as LADWP and SMUD are not subject to Rule 21 and run their own interconnection programs.

One boundary worth noting: Rule 21 is separate from the Net Billing Tariff, the successor to NEM 2 that the CPUC adopted through Decision 22-12-056.2California Public Utilities Commission. Net Billing Tariff Rule 21 decides whether your system can connect. The Net Billing Tariff decides how you get paid for exports. You have to satisfy both, and the utility portal asks which compensation program you’re enrolling in as part of the interconnection application.

Smart Inverter and Equipment Requirements

Every system connecting under Rule 21 must use a certified smart inverter. The current certification standard is UL 1741 Supplement SB, which tests inverters against IEEE 1547-2018 and adds requirements for dynamic voltage support, frequency ride-through, and other grid-stabilizing functions. The older UL 1741 Supplement SA still exists in some legacy systems, but new installations are expected to meet SB.

Before you buy an inverter, confirm it appears on your utility’s list of pre-approved equipment. Submitting an application with an uncertified inverter fails Screen B during the technical review and sends the project back to the start.

What Goes Into the Application

Applications are submitted through each utility’s online portal. The documentation requirements are consistent across PG&E, SCE, and SDG&E:

  • AC and DC ratings of the panels and manufacturer model numbers for every inverter
  • A site map showing the utility meter, main service panel, and point of connection
  • A professionally prepared single-line electrical diagram from panels through inverters to the main breaker and meter
  • Array tilt, orientation, and shading factors, which the utility uses to model expected output
  • Total nameplate capacity and quantity for every generating and storage component

Accuracy matters. If inverter power factor settings or aggregate nameplate capacity don’t match the equipment labels, the utility’s system flags the discrepancy and the back-and-forth can delay the project by weeks. Installers who file Rule 21 applications regularly check every field against the spec sheets before submitting.

Application Fees by Utility

The upfront fee depends on your utility and which compensation program applies:

  • PG&E charges $145 for NEM-2 and Net Billing systems of 1 MW or less.3Pacific Gas and Electric Company. Net Energy Metering Program
  • SCE charges $800 for a standard Rule 21 interconnection request.4Southern California Edison. Frequently Asked Questions for Rule 21 Tariff
  • SDG&E charges $132 for NEM-2 systems of 1 MW or less, $800 for non-NEM systems above 1 MW, and $0 for original NEM-1 systems and qualifying non-NEM solar that doesn’t sell power back.5San Diego Gas & Electric. Electric Rule 21

These are application fees only. Projects pushed into a Detailed Study pay study deposits on top.

The Fast Track Screens

Most residential and small commercial projects go through Fast Track review, which runs your project through technical screens labeled A through M.6Pacific Gas and Electric Company. Electric Rule No. 21 – Generating Facility Interconnections Pass them all and the project moves toward approval without engineering studies.

Each screen tests a specific grid issue:

  • Screen A checks whether the connection point sits on a networked secondary system, which has tighter limits on distributed generation.
  • Screen B verifies your inverter and other equipment are certified and on the utility’s approved list.
  • Screen C tests whether starting the generator causes voltage drops beyond acceptable limits. This matters mainly for motor-started generators, not typical solar inverters.
  • Screen D checks whether your system’s output exceeds the rating of the transformer or secondary conductor serving your property.
  • Screen E flags single-phase generators that would create unacceptable phase imbalance.
  • Screens F and G test whether fault current contribution stays within safe limits and doesn’t exceed the interrupting capability of existing protective equipment.
  • Screen M checks whether aggregate generation on your line section stays below the hosting capacity threshold, generally 15% of the line section’s peak load unless the utility’s Integration Capacity Analysis shows more room.

For a typical residential installation with a listed inverter on a standard service, screens C, E, and F rarely cause trouble. Screen M is where projects on already-saturated circuits tend to hit a wall. If your neighborhood already has heavy solar penetration, cumulative generation on the feeder may have consumed the available hosting capacity.

What Happens When You Fail a Screen

Failing a Fast Track screen doesn’t end the project. It moves you into a Supplemental Review, where utility engineers look more carefully at whether the flagged issue is a real problem or just a conservative screen result. Many projects that fail on paper still pass supplemental review because the screens are intentionally cautious.

If Supplemental Review confirms a genuine grid constraint, the utility opens a Detailed Study. That includes a System Impact Study modeling how your system affects the local distribution network and a Facilities Study identifying physical upgrades to accommodate it, which may involve transformer replacements, conductor upgrades, or new protective equipment.

You pay for those studies. For systems of 5 MW or less, the System Impact Study deposit is around $10,000 and the Facilities Study around $15,000. Actual costs can come in below the deposit, with the balance refunded, or above it. Residential projects rarely reach this stage, and when they do, the cost of required grid upgrades often exceeds what makes the project financially viable. This is the point where many homeowners either shrink the system or move to a limited-export configuration.

Non-Export and Limited-Export Options

Rule 21 does not require your system to export power. Configuring it to limit or eliminate exports opens a faster, simpler review path. The tariff defines several Power Control System options that let you size the solar array larger than what the grid can accept, as long as certified controls prevent excess power from flowing back:

  • Option 8 (Non-Export): a certified Power Control System drops export to zero within two seconds of detecting backfeed.
  • Option 9 (Limited Export): the PCS holds exports at or below an approved limit, responding within two seconds when exceeded.
  • Option 10 (Non-Export with Inadvertent Export): similar to Option 8 but allowing a response time up to ten seconds, acknowledging brief small exports may occur.
  • Option 11 (Limited Export with Inadvertent Export): a limited export cap with the ten-second response window.
  • Option 12 (Limited Export with Generation Profile): uses a PCS certified to UL 3141 with an integrated schedule, capping exports within two seconds.

Non-export configurations can bypass most Fast Track screens entirely. Pairing solar with storage and self-consuming most of your generation makes a non-export or limited-export setup a practical way to avoid study costs. The tradeoff: you won’t earn export credits under the Net Billing Tariff for generation your controls block from reaching the grid.

Timelines and Permission to Operate

The CPUC set mandatory timelines for each step of the process through Decision 20-09-035, with a benchmark requiring utilities to hit those deadlines 95% of the time across 19 individual steps. The decision allowed 60 business days for design of interconnection-related distribution upgrades and another 60 business days for construction.7California Public Utilities Commission. Assigned Commissioners Scoping Memo and Ruling R.25-08-004

In practice, the utilities have struggled with these deadlines. CPUC compliance data from 2025 showed on-time completion rates for some review steps as low as 27% to 45%, well below the 95% target. Residential system impact studies at some utilities showed zero on-time completions in the first half of 2025. If you’re planning around a federal tax credit deadline or a financing cutoff, build in substantial buffer. Delays of several months beyond the tariff deadlines are common.

Once your system passes technical review and your local building department signs off on the physical installation, the utility issues a Permission to Operate letter. PTO is your legal authorization to energize the system. Operating before you receive it violates your interconnection agreement and can lead to disconnection. The gap between passing inspection and receiving PTO is one of the timeline steps where compliance has been weakest.

Changing the System After Approval

Adding panels, swapping inverters, or expanding battery capacity after approval triggers Rule 21’s modification provisions. Not every change requires a new application, but the thresholds are specific.6Pacific Gas and Electric Company. Electric Rule No. 21 – Generating Facility Interconnections

Changes that do not require a new application:

  • Like-for-like replacements with equivalent components having the same or smaller nameplate ratings, the same or lower fault current contribution, and the same connection type, as long as total system output doesn’t exceed the original agreement
  • Adding capacity that keeps the total nameplate below 100 kW
  • Increasing nameplate to more than 100 kW but staying within 110% of the original approved capacity

Changes that do require a new application:

  • Capacity above 100 kW that also exceeds 110% of the original approved capacity
  • Replacing equipment with larger units without using inverter power controls to hold active power output to the size in the original agreement

For most residential systems well under 100 kW, adding a few panels or swapping to a slightly larger inverter won’t require a new application. On commercial systems, check the math. Going from 95 kW to 115 kW crosses the 100 kW threshold and exceeds 110% of the original, requiring a full new application.

Disputing a Utility Decision

If you disagree with a utility’s engineering study results, cost allocation, or reading of Rule 21, the CPUC offers a voluntary path called the Expedited Interconnection Dispute Resolution process.8California Public Utilities Commission. Expedited Interconnection Dispute Resolution Intake Form You submit an EIDR Intake Form by email to the CPUC Energy Division with your application, the utility’s study results, and correspondence showing your attempts to resolve the issue directly. Documenting that direct effort first is required.

A technical panel administered by the University of California reviews the dispute and issues a recommendation to the CPUC Executive Director, who then issues a binding opinion to the utility. If you disagree with the Executive Director’s decision, you can appeal to the full CPUC. Documents you submit are published on the CPUC’s public web page unless you file a redacted confidential version alongside the public one.

EIDR is most useful when a utility has assigned upgrade costs that seem disproportionate, applied screens in a way that doesn’t match the tariff language, or imposed study requirements the project shouldn’t trigger. For a typical residential installation, the effort of pursuing a dispute rarely makes financial sense. For larger commercial projects where study-driven upgrade costs reach six figures, having a formal review available is a meaningful backstop.