California Electric Rule 21: Application, Review, and Timelines

If you’re installing solar panels or battery storage in PG&E, SCE, or SDG&E territory, the California Electric Rule 21 interconnection requirements control everything between your equipment and the grid: the inverter you can use, the application you file, the technical screens your project must pass, the fees you pay, and the Permission to Operate letter that lets you legally turn the system on. Rule 21 is a tariff administered by the California Public Utilities Commission, and no system in investor-owned utility territory connects without satisfying it.¹

Who Rule 21 Covers

Rule 21 applies to customers of Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric.¹ A 5-kilowatt rooftop array and a multi-megawatt commercial storage project move through the same tariff framework. Municipal utilities such as LADWP and SMUD have their own interconnection rules and are not subject to Rule 21.

Rule 21 is also separate from the Net Billing Tariff, which the CPUC adopted through Decision 22-12-056 as the successor to NEM 2.² Rule 21 decides whether your system can physically connect. The Net Billing Tariff decides how your exports are credited. You need to satisfy both, and the utility’s interconnection portal asks which compensation program you’re enrolling in alongside the technical data.

Smart Inverter Certification

Every generating system 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. UL 1741 Supplement SA was developed with Rule 21’s earlier smart inverter requirements and remains in some legacy systems, but new installations are expected to meet SB, which adds dynamic voltage support, frequency ride-through, and other grid-stabilizing functions.

The autonomous functions required of smart inverters were adopted in phases through the CPUC’s Smart Inverter Working Group. Phase 1, approved in late 2014, set seven functions including voltage and frequency ride-through, which keep your system connected during minor grid disturbances rather than tripping offline. Phase 2 added communications capabilities. Phase 3 covered advanced functions like reactive power management.³

Before you buy an inverter, confirm it appears on your utility’s list of pre-approved equipment. An uncertified inverter will fail the equipment screen during technical review and stall the project.

What Goes in the Application

You submit the interconnection application through your utility’s online portal. The core documentation is consistent across PG&E, SCE, and SDG&E:

Equipment specifications, including 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 the point of connection to the grid.
A professionally prepared single-line electrical diagram covering panels through inverters to the main breaker and meter.
Array characteristics: 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 figures don’t match the equipment labels, the utility’s automated review flags the discrepancy and the correction cycle can add weeks. Check every field against the spec sheets before you submit.

Application Fees

Upfront fees vary by utility and tariff program:

PG&E: $145 for NEM-2 and Net Billing systems of 1 MW or less.⁴
SCE: $800 for a standard Rule 21 interconnection request.⁵
SDG&E: $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.⁶

These are application fees only. If your project is routed into a detailed study, study deposits are additional.

Fast Track Screens

Most residential and small commercial projects move through Fast Track review, a sequence of technical screens labeled A through M.⁷ Pass them all and you proceed toward approval without engineering studies. Each screen tests one specific grid concern:

Screen A: whether the point of connection sits on a networked secondary system, which has tighter limits on distributed generation.
Screen B: whether the inverter and other equipment are certified and listed on the utility’s approved list.
Screen C: whether starting the generator causes unacceptable voltage drops (mainly a concern for motor-started generators, not typical solar inverters).
Screen D: whether system output exceeds the rating of the serving transformer or secondary conductor.
Screen E: whether a single-phase generator creates unacceptable phase imbalance.
Screens F and G: whether fault current contribution stays within safe limits and within the interrupting capability of existing protective equipment.
Screen M: whether aggregate generation on the line section stays below hosting capacity, generally 15% of 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 saturated circuits tend to hit a wall. Neighborhoods with heavy existing solar penetration may have already used up the available hosting capacity on the feeder.

Supplemental Review and Detailed Studies

Failing a Fast Track screen doesn’t end the project. It moves you into Supplemental Review, where utility engineers decide whether the flagged issue is a real constraint or a conservative screen result. Many projects that fail on paper clear this stage.

If Supplemental Review confirms a genuine constraint, the utility initiates a Detailed Study: a System Impact Study modeling how your system affects the local distribution network, and a Facilities Study identifying the physical upgrades needed to accommodate it.¹ Upgrades can include transformer replacements, conductor upgrades, or new protective equipment.

You pay for the 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 may come in lower, with the balance refunded, or they can exceed the deposit. Residential projects rarely reach this stage, and when they do, the upgrade costs often make the project uneconomic. That’s the point where many homeowners either downsize the system or shift to a limited-export configuration.

Limiting Exports to Simplify Review

Rule 21 doesn’t require your system to export power. Configure the system to limit or eliminate exports and you can often qualify for a faster, simpler review. The tariff defines several Power Control System options that let you size an array larger than the grid would otherwise accept, provided certified controls stop excess power from flowing back:⁷

Option 8 (Non-Export): a certified Power Control System reduces export to zero within two seconds of detecting backfeed.
Option 9 (Limited Export): the PCS holds exports at or below an approved cap, responding within two seconds.
Option 10 (Non-Export with Inadvertent Export): similar to Option 8 but allows up to a ten-second response window.
Option 11 (Limited Export with Inadvertent Export): combines a limited cap with the ten-second 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. If you’re pairing solar with storage and plan to self-consume, a non-export or limited-export setup can simplify interconnection and avoid study costs. The tradeoff is that you won’t earn Net Billing Tariff credits for any generation the controls block from reaching the grid.

Timelines and Permission to Operate

The CPUC has set mandatory timelines for each step of interconnection, with a benchmark requiring utilities to meet those deadlines 95% of the time across 19 process steps. Design of interconnection-related distribution upgrades gets 60 business days, with another 60 business days for construction.⁸

Compliance has lagged badly. CPUC data from 2025 showed on-time completion rates as low as 27% to 45% at some steps, far below the 95% target, and residential system impact studies at some utilities showed zero on-time completions in the first half of 2025. If you’re planning around federal tax credit timing or a financing deadline, build in substantial buffer. Delays of several months beyond the tariff deadlines are common.

Once technical review clears and the local building department signs off on the installation, the utility issues a Permission to Operate letter. PTO is your legal authorization to energize. Operating before you receive it violates the interconnection agreement and can lead to disconnection. The wait between inspection and PTO is one of the weakest points in utility compliance.

Changing the System After Approval

Adding panels, swapping inverters, or expanding battery capacity after approval triggers Rule 21’s modification rules. Not every change requires a new application, but the thresholds are specific.⁷

No new application needed for:

Like-for-like replacements with equivalent components at the same or smaller nameplate rating, same or lower fault current, and same connection type, as long as total output stays within the original agreement.
Capacity additions that keep total nameplate below 100 kW.
Increases above 100 kW that stay within 110% of the original approved capacity.

A new application is required when nameplate capacity goes above 100 kW and exceeds 110% of the original approved capacity, or when you replace equipment with larger units and don’t use inverter power controls to hold active power output to the originally approved size. For most residential systems well under 100 kW, adding a few panels or stepping up to a slightly larger inverter won’t force a new application. On a commercial system, check the math: going from 95 kW to 115 kW crosses the 100 kW threshold and exceeds 110% of the original, which means a full new application.

Disputing a Utility Decision

If you disagree with a utility’s study results, cost allocation, or reading of Rule 21, the CPUC offers a voluntary alternative to litigation called Expedited Interconnection Dispute Resolution.⁹ You file an EIDR Intake Form with the CPUC Energy Division along with your application, the utility’s study, and correspondence showing your attempts to resolve the issue directly. That documentation of prior effort is required.

A technical panel reviews the dispute and recommends a resolution to the CPUC Executive Director, who issues a binding opinion to the utility. The Executive Director’s decision can be appealed to the full CPUC. Submitted documents are published on the CPUC’s public web page unless you file a redacted public version alongside a confidential one.

EIDR is most useful when a utility assigns upgrade costs that look disproportionate, applies screening in a way that doesn’t match the tariff, or imposes study requirements the project shouldn’t trigger. For a typical residential installation, the cost of pursuing a dispute rarely makes sense. On larger commercial projects, where study-driven upgrades can run into six figures, having a formal review channel is a meaningful safeguard.

1
California Public Utilities Commission. Electric Rule 21 – Generating Facility Interconnections
2
California Public Utilities Commission. Net Billing Tariff
3
California Public Utilities Commission. Smart Inverter Working Group Phase 2 Recommendations
4
Pacific Gas and Electric Company. Net Energy Metering Program
5
Southern California Edison. Frequently Asked Questions for Rule 21 Tariff
6
San Diego Gas & Electric. Electric Rule 21
7
Pacific Gas and Electric Company. Electric Rule No. 21 – Generating Facility Interconnections
8
California Public Utilities Commission. Assigned Commissioners Scoping Memo and Ruling R.25-08-004
9
California Public Utilities Commission. Expedited Interconnection Dispute Resolution Intake Form