Solar Interconnection Application: Fees, Limits, Timelines

PG&E's Electric Rule 21 is one PDF in the company's tariff book, and it runs 290 sheets. Every residential solar interconnection application in that territory is judged against it. It also carries four different effective dates inside itself. I pulled it on 20 September 2026 and counted them: 271 sheets are stamped Advice 7692-E, effective 29 August 2025; ten still carry Advice 7254-E from 2 May 2024; eight carry 7540-E from 17 April 2025; and one sheet, number 25, has not been touched since 28 February 2023.

That document decides whether your array is allowed to connect, what the application costs, how big the system may be, and how many days the utility has to answer you. None of it is written for a homeowner. All of it is public, free, and searchable, and the part you actually need is about nine pages long.

The rules are in three documents, and they are not interchangeable

Almost every argument about interconnection is really an argument about which of three layers someone is quoting.

The first layer is the statute or commission rule. Virginia's net metering terms sit in § 56-594 of the Code of Virginia (read 20 September 2026). Arizona's process is set by rules in the Arizona Administrative Code, cited throughout APS's own manual as A.A.C. R14-2-2616 through R14-2-2621. California's framework is maintained at the CPUC. This layer sets the outer boundaries and the deadlines that bind the utility.

The second layer is the utility's own tariff rule, filed with and approved by that commission. PG&E's Electric Rule 21 is the specimen used throughout this article. It is enforceable against the utility, and it is where the fee table lives.

The third layer is the engineering manual and the application forms. APS's Interconnection Requirements for Distributed Generation, Revision 10.0 (read 20 September 2026) numbers its body to page 85 and then runs four lettered appendices: protection settings, metering arrangements, drawing standards, commissioning steps, screens. It is referenced by the tariff, it changes more often, and it is not filed as a tariff sheet.

The practical consequence is worth stating plainly. The answer you are looking for is usually in the third layer, the citation you need in an argument is in the second, and the deadline anyone is actually obliged to meet is in the first.

Finding it: the words that work, and the ones that don't

Start at the tariff library, not the solar page. PG&E's index at pge.com/tariffs divides into gas and electric versions of seven sections: rate schedules, preliminary statements, rules, maps, contracts and deviations, forms, and title. Interconnection is in rules. A reader who searches only the rate schedules will never find it.

Searching for solar is the mistake. Rule 21 is titled "Generating Facility Interconnections," and the word solar appears nowhere in the name. The vocabulary that finds these documents is:

• interconnection, generating facility, parallel operation
• distributed generation, customer-owned generation, DG
• permission to operate, authorization to operate
• generator interconnection agreement

The same gap runs the other way. A utility's consumer pages use plan names that do not appear in the tariff, and the tariff uses acronyms that never appear on the consumer pages. Rule 21 calls California's current residential structure NBT-1. You will not see that string on a sales proposal.

Then look outside the tariff book. APS's engineering manual sits on its residential solar pages rather than in its tariff filings, and the application forms sit somewhere else again, on the utility's interconnection portal. Three addresses, one subject.

Read the header of the sheet before you read the sheet

Every page of a CPUC-jurisdictional tariff carries the same block at top and bottom: a Cal. P.U.C. sheet number, the sheet number it cancels, the advice letter that put it there, a submitted date and an effective date.

That header is why a tariff PDF is trustworthy in a way a utility web page is not. It tells you which filing produced the language, and it tells you whether the page in front of you is current. It also means one document can be internally mixed. Sheet 17 of Rule 21 is §B.5, the sheet stating that IEEE 1547-2018 and its related certification requirements apply wherever the voltage at the point of interconnection is less than 50 kV. It is still on Advice 7254-E from May 2024. Sheet 56, thirty-nine sheets later, is on 7692-E from August 2025. Both are in force. Neither is a draft.

APS's manual has no sheet numbers. It has a revision number on every page and a warning line: "Printed Copies are for Reference Purpose Only. Refer to Electronic Copy for Latest Version." That is a weaker promise. With a tariff sheet you can prove what was in force on a given date. With a revision-numbered manual you can only prove what it says today.

So when a number goes into your spreadsheet, put the sheet number and the date you read it in the cell beside it. The same discipline applies to the rate code on your own bill: a schedule is only a fact as of a date.

The thresholds that decide which process you are in

Interconnection rules are step functions. Nothing scales smoothly; you sit on one side of a line or the other, and the line is usually a round number nobody mentions in a sales conversation.

A typical residential array sits below every one of these lines, which is exactly why the process feels invisible until something pushes it over one. A 7.6 kW inverter is nowhere near 30 kVA. Two of them are not either. What moves a house across a line is rarely panel count — it is adding storage, upgrading the service, or hanging a second array on a second meter.

Notice what the insurance row shows, too. APS requires liability coverage only for rotating machines above 50 kW. For everyone else §5.3(A) is a recommendation: consult your insurer, because an existing policy "may not have contemplated" the addition. A recommendation is not a requirement, and an installer who says the utility requires a policy is quoting the wrong paragraph.

What the paperwork costs, in two adjacent rows

Table E.1 of Rule 21 is one page, and the distance between two of its rows is larger than most people's first-year savings.

Above 5 MW the deposit becomes $50,000 plus $1,000 per MW, capped at $250,000, and there is an optional $1,000 fault current study plus a $150-per-person-hour charge for additional commissioning test verification. Section E.3 then restates the exemptions in words: the application fee is waived for NEM-1 outright, and applicants at 1 MW or less on NEM-2 or NBT-1 are exempt from the costs of interconnection studies.

Which row you are in is a classification question rather than an engineering one, and it is decided by the tariff you are applying under, not by the size of your roof. Worth reading twice before anyone submits on your behalf.

Two more prices sit in the same rule and are easy to miss. A standard pre-application report costs $300 and obliges the utility to return distribution data within ten business days. An enhanced behind-the-meter interconnection package costs $800, plus another $100 where applicable, includes a physical verification based on field confirmation, and takes thirty business days. Both are optional. Both exist because the answer to "is there room on this circuit" is otherwise unknowable from the street.

None of these figures includes the permit fee charged by your city or county. The tariff does not mention it, because the tariff is not about that.

System size is capped twice, in two different units

Here is where the arithmetic bites, and where the most common confusion lives.

Virginia caps a residential eligible customer-generator at 25 kW of capacity. It then caps the same facility a second way: for anything installed after 1 July 2020, capacity may not exceed 100 percent of expected annual energy consumption in a Phase I utility's territory, or 150 percent in a Phase II utility's, "based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available." Both versions of the statute on the books in September 2026 — the current one and the one taking effect 1 January 2027 — carry the same pair of limits.

Work it with your own numbers, not an average:

Prior 12 months of billing history            9,850 kWh
Territory                        Phase II  ->  cap = 150%

Allowed annual production   9,850 x 1.50  =  14,775 kWh
Specific yield for your site (PVWatts)    =   1,430 kWh per kW-DC
Maximum array          14,775 / 1,430     =    10.3 kW-DC
Flat residential cap                      =      25 kW  (not binding here)

The specific yield is the one input you have to produce yourself, and producing it is the subject of checking a quote against PVWatts. Everything else comes off your own twelve months.

Now the caveat that matters more than the answer. The statute states the cap as capacity and measures it against consumption — kilowatts against kilowatt-hours. Those are not the same unit, and the statute does not supply the conversion. The utility's implementing tariff does, and utilities do it differently. So the block above is the shape of the calculation, not a result you can hand to anyone. Find the conversion in your own tariff before you size anything on it.

The related trap is the phrase "the 120 percent rule." That number comes from the busbar allowance in the National Electrical Code, it is enforced by your electrical inspector, and it governs where a backfeed breaker may land in your panel. It has nothing to do with how large a system your utility will interconnect. Two separate documents, two separate officials, two separate refusals available. People hear one percentage and assume there is one rule. If you want the language rather than the folklore, the question for your inspector is which edition of the code your jurisdiction has adopted — APS, for one, writes its own requirements against NEC-2023 — because that is the book the busbar arithmetic gets run out of.

The clocks, and the sentence that softens all of them

Rule 21 commits to specific counts in business days, defined in the rule as Monday through Friday excluding federal and state holidays.

• 10 business days for a first written notification saying whether the application is complete and valid
• 15 business days for the result of initial review
• 10 business days for you to elect supplemental review or withdraw, with one ten-day extension available
• 20 business days for supplemental review once it is authorized and paid for
• 15 business days for you to request an interconnection agreement after a cost estimate arrives, and 15 business days for the utility to produce the draft
• 90 calendar days for you to sign and return it, with comments due within 30
• 30 business days for permission to operate

Add the clean path and you get 10 + 15 = 25 business days to clear review, then up to 30 more for permission to operate: 55 business days, a shade over eleven working weeks before holidays. Fall into supplemental review and it becomes 85, roughly seventeen weeks.

Two clauses change how that sum should be read.

The first is the trigger. The thirty-day permission clock does not start when you apply. Rule 21 §D.13.b says approval is normally processed not later than thirty business days following receipt of three things: the completed application with supporting documents and payments, the signed generator interconnection agreement, and evidence of final electrical inspection clearance from the authority having jurisdiction. That last item arrives only after the system is built and your local inspector has signed off. Your city is upstream of your utility, and a slow inspection does not shorten the utility's thirty days; it postpones the day they begin.

The second is §F.1.d, which says the utility "shall use Reasonable Efforts in meeting all the timelines set out in this Rule," and requires each distribution provider to designate an ombudsman with authority to resolve disputes over missed timelines, with contact details posted on its website. So the numbers are real commitments with a soft standard attached and a named escalation path. The one hard obligation nearby is narrower and more useful: if the thirty-day period cannot be met, the utility must notify you and the Commission of the reason and the expected completion date. Ask for that notice by name when the clock runs out.

The escalation path is written into the same section, which is unusual enough to be worth using. Contact the ombudsman first; PG&E prints the address in the rule itself, Rule21.Ombudsman@pge.com. If the ombudsman has not resolved the dispute within ten business days, Rule 21 sends you either to the Commission's Consumer Affairs Branch or, by mutual agreement, to mediation through the CPUC's Alternative Dispute Resolution coordinator, with "Rule 21" required in the subject line. A formal complaint before the Commission stays available at any time.

There is a clock on you as well. Under §D.13.d, a fast-track application on NEM-1, NEM-2 or NBT-1 at 1 MW or less that goes more than a year from the utility's written validation without a signed agreement, or whose facility is not approved for parallel operation within a year of completing review, is subject to withdrawal. Two escapes sit in the same sentence: the utility may not deem it withdrawn if you provide reasonable evidence the request is still active, or if the delay is at no fault of yours. Both are worth knowing before that letter arrives.

Arizona is blunter, and here the sourcing matters. Section 16.4 of the APS manual states that A.A.C. R14-2-2621(G) requires interconnection within 180 days of application approval, and that R14-2-2604(A)(7) allows a 90-day extension, which APS says it will approve on a showing that permits have been acquired, equipment purchased, construction commenced, or additional funds spent in reliance on the interconnection agreement. That is APS restating the rule rather than the rule's own words; the code itself is published by the Arizona Secretary of State, and the manual prints the address.

And a change resets the whole thing. APS §16.7 says modifications made during the interconnection process "may render previous reviews and/or studies invalid," and that this "will reset all timelines and may require new reviews and/or studies be completed." A late panel swap is not a detail.

Where a battery moves the paperwork

Footnote 2 of PG&E's Rule 21 Generator Interconnection Application, Form 79-1174-03 (Advice 7728-E, effective 10 October 2025, read 20 September 2026) points net billing customers with solar or wind under 30 kW to "simpler, shorter forms" — and applies that pointer only to systems "that are not paired with Energy Storage." Adding a battery puts a residential project back on the long form, which is seven pages of tariff-program selection feeding fourteen lettered attachments.

The short forms exist, and the reason a search for them comes up empty is that the footnote misnumbers its own forms. It names them 79-1151-A03 and 79-1151-B-03. The tariff book files them without that first hyphen: 79-1151A-03, the agreement and customer authorization, on Advice 7661-E effective 30 September 2025, and 79-1151B-03, the application itself, on Advice 7728-E effective 10 October 2025. Both are titled for solar and/or wind generating facilities of 30 kilowatts or less, and both were read on 20 September 2026. Search the tariff library for 79-1151 rather than for the string printed in the footnote. The footnote also gives a shortcut that does still resolve: pge.com/gen.

Arizona runs the opposite way on the same question. Section 1 of the APS manual lists an Expedited Interconnection Process under A.A.C. R14-2-2623 for a non-exporting inverter-based energy storage facility, or an inadvertent-export facility, of 20 kW or less. Storage there is not a reason to leave the fast lane; it has a lane of its own. Which one you land in turns on whether the battery is allowed to export, and that is a control-scheme question answered on the drawings.

The drawings then carry their own weight. Under §16.2, where a residential design departs from the standard sample diagrams, APS may ask in writing for electrical drawings stamped by a Professional Engineer registered in Arizona, or for a copy of the AHJ building permit — and "no Interconnection approval shall be provided until the AHJ building permit has been issued and a copy provided to the Utility." If the tie-in runs through a meter socket adapter, §8.1(G)(3) adds a checklist of its own, including that any existing generation or storage already interconnected at the property be identified on both the application and the submitted drawings.

Storage also changes what the export side of the tariff pays you, which is a separate document again and a much larger number — that is the subject of how California prices export credits hour by hour. The interconnection rule decides whether the battery may be there at all and under what control scheme. The billing schedule decides what it earns.

What the interconnection tariff does not decide

It does not approve your design. Rule 21 §D.5 reserves the right to review and inspect, then says the review and authorization "shall not be construed as confirming or endorsing Producer's design or as warranting the Generating Facilities' and/or Interconnection Facilities' safety, durability or reliability." APS says much the same thing twice: in the preamble to §16, where notification that a design "appears to be in conformance" is declared not to be approval of that design, and again in §16.3(E). Passing interconnection review is not a second opinion on your installer's work.

It does not decide your permit, your roof, your HOA, or your rate plan. It does not set the price of an exported kilowatt-hour; that lives in a rider or schedule with its own sheet number. And it does not stop you from operating illegally — §D.1 requires an executed agreement and the utility's "express written permission before Parallel Operation," which is the clause that turns switching on early from impatience into a tariff violation.

What it does decide is binary and worth knowing before a deposit changes hands: whether this system, at this address, on this circuit, connects under the fast process or gets routed into study.

Twenty minutes, three tabs, six lines

Open your utility's tariff library and find the rule whose title contains interconnection or generating facility. Open the engineering manual if there is one. Open your last twelve months of billing history.

Then write down six things, each with the sheet number or section and the date you read it:

1. The application fee for the tariff you will actually be on, and the fee for the row below it.
2. The capacity threshold that keeps you on the short review path.
3. The system size cap, in whatever unit your tariff states it, and the conversion it uses.
4. The trigger event for the permission-to-operate clock.
5. Whether pairing storage changes the form, the screens, or both.
6. The ombudsman or escalation contact, and the step that comes after it, before you need either.

Then hand those six lines to whoever wrote your proposal and ask which of them their schedule assumed. If the timeline in the proposal is shorter than the clocks in your own tariff, the gap is not optimism. It is an unpriced assumption, and it belongs on the same list as the twelve items a proposal must show.