FIELD NOTE · SUPPLEMENTAL SET
Nine years, not twenty: the export tariff that made the battery the product
ISSUEDJULY 11, 2026DRAWN BY THE NIGHTLY SWEEP
The rule that rewrote this trade is D.22-12-056, adopted December 15, 2022. It moved export compensation off the retail rate. That's the whole story: the battery is the product now, and the panels are how you refill it.
The Commission set a method, not a price. Export compensation comes off the Avoided Cost Calculator, the decision's own section heading at 8.5.1 says so, and the credit for a kilowatt-hour you push out now depends on the month and the hour rather than on the retail rate. Weekdays price differently from weekends and holidays.
Twelve months, twenty-four hours, two day types. That's 576 values. The Commission agreed the idea looked like an excessive amount of complexity to manage and explain to customers, then rejected seasonal averaging anyway on cost-shift grounds. D.22-12-056 at 143. PG&E calls the resulting line item the Energy Export Credit.
There's a second clock inside the first one. A complete interconnection application filed between April 15, 2023 and December 31, 2027 earns a locked nine-year schedule of hourly values, running from PTO. Schedule NBT draws those values from the Avoided Cost Calculator adopted as of January 1 of the year the complete application lands, so the filing date picks the vintage, and filing after the window gets you no locked schedule at all.
The residential adder rides the same nine years. ACC Plus was $0.02200 per kilowatt-hour for a 2023 vintage, steps down twenty percent a year, and lands at $0.00440 for 2027.
Here's the part that catches people. The legacy period and the lock-in attach to the customer who caused the system to be installed, not to the roof and not to the meter. A buyer of a house with panels inherits the hardware and none of the tariff, and Schedule NBT lists a Change of Party customer right there under the ACC Plus exclusions. The array conveys. The deal doesn't.
A salesman sold that array on midday export paying the loan. It generates what it was sold to generate. It earns a fraction of what it was sold to earn. The money moved to whichever hours the customer can shift load into, which is why the service upgrade shows up in the permit record before the array does.
Be careful what the decision promised. D.22-12-056 adopted a nine-year simple payback for stand-alone residential solar as the target, and $3.30 per watt as the 2023 cost of solar. Those are assumptions, not measured outcomes on your jobs.
California's median residential system in 2024 was 5.7 kW. The national median was 7.2 kW. Small roofs, expensive evening hours, and a tariff that pays you most for the power you never send anywhere. Some of those batteries have a second income now through grid programs, which is its own subject.
The warehouse owner was excluded from the glide path on purpose. Section 8.5.2 says commercial customers will not receive the ACC Plus, because their paybacks are shorter without it. PG&E's Schedule NBT lists Non-Residential third in the ACC Plus exclusions, under Change of Party customers. The one payback range on the record is the Commission's own, and it's 5.8 to 9.4 years.
Then the multi-meter properties lost the economics they were built around. Effective February 15, 2024, D.23-11-068 closed NEM2 load aggregation to new applicants and moved them onto NBTA, where imports and exports no longer net against each other. Special Condition 6 of Schedule NBT still lets a school, a farm or a warehouse campus run one array across several service points. The parcels have to be contiguous and under common ownership. What it stopped doing is netting.
SB 1374 would have required the Commission to restore account-level netting by July 1, 2025. The Governor returned it without signature on September 27, 2024, writing that it would compound the challenge of electric bill affordability.
The federal side pushes the same direction. Under 26 U.S.C. 48E(e)(4)(A) the credit doesn't apply to qualified property placed in service after December 31, 2027. P.L. 119-21 applies that termination only where construction began after July 4, 2026.
IRS Notice 2025-42 makes the Physical Work Test the sole method of establishing beginning of construction. Section 7 limits that to facilities whose construction had not begun before September 2, 2025, so anything already under way by then stays under the older beginning-of-construction notices, safe harbor included. Section 6 carves out a low output solar facility, meaning nameplate capacity in alternating current no greater than 1.5 MW.
Storage is carved out completely. 48E(e)(4)(C) exempts any energy storage technology placed in service at an applicable facility. Read those together and the warehouse sharpens toward a storage-weighted design.
The code is pushing the same way. California's 2022 Energy Code took effect for permit applications filed on or after January 1, 2023, and it prescribes PV on newly constructed nonresidential buildings where at least 80 percent of floor area is a listed occupancy, warehouse included. A building required to install PV under Section 140.10(a) also has to install battery storage sized per Equations 140.10-B and 140.10-C, subject to the exceptions in Section 140.10(b), and which of those your building lands in is a plan-check answer.
That's the argument I've made in a plan-check line. The spread underneath it doesn't hold it up.
DISTRIBUTION UPGRADES TRIGGERED, BY PROJECT SIZE (PG&E, 2021 CPUC EVALUATION, PERCENT OF PROJECTS) UNDER 30 KW 0.2 30 TO 100 KW 7.0 100 KW TO 1 MW 11.2 1 MW AND ABOVE 19.1
Under 30 kW, distribution upgrades triggered on 0.2 percent of PG&E projects. At 1 MW and above, 19.1 percent. Size decides whether an upgrade gets triggered at all. It does not decide duration, and Guidehouse says so directly: total time to an agreement or PTO varies by track, not by project size or technology. Projects 100 kW and up averaged 137.9 business days against 122.7 for everything, which is twelve percent on ten times the nameplate.
So the track is the whole story, and a design picks its own track. A designer sized that array to the roof instead of to the service. The screen it failed is published.
Fifteen percent of the maximum loading of the line section, counting the new generating facility and whatever generation already sits there. Above 1 MW the customer carries the triggered upgrades and the studies behind them, per Schedule NBT and Section 3.4 of SCE's interconnection handbook. There's also a 150 percent output-power ratio on paired storage above 10 kW AC, which got waived under D.20-06-017 and stayed waived past August 16, 2025 pending a further Commission decision. Size against it and you're designing to a limit nobody is enforcing this year.
The first two were knowable from the single-line, before the application went in. The screen caught a design problem early.
Price it as a calendar. SCE charges $94 to review a facility up to 1 MW and $800 above that line. Rule 21 gives the utility 10 business days to validate a clean application. Then 15 to complete Initial Review.
Supplemental Review is 30 business days, 10 for the customer to elect it and 20 for the utility to run it. A System Impact Study is 150 business days measured from Initial Review or 145 from Supplemental Review, and Guidehouse Table 14 carries both figures, which is the tell that they're branches and not a stack. Then it's 15 business days for a draft agreement and 90 calendar days for the customer to sign it. PTO typically issues 5 to 10 business days after the assigned engineer hands the project back.
The engineer who can tell you which branch you're on is reading your single-line against a line section you can't see from the roof. Bid the Solar & Battery work that's already cleared its service question. Watch the panel and service filings. Those land first, and they tell you what the feeder was willing to accept.
The Commission set a method, not a price. Export compensation comes off the Avoided Cost Calculator, the decision's own section heading at 8.5.1 says so, and the credit for a kilowatt-hour you push out now depends on the month and the hour rather than on the retail rate. Weekdays price differently from weekends and holidays.
Twelve months, twenty-four hours, two day types. That's 576 values. The Commission agreed the idea looked like an excessive amount of complexity to manage and explain to customers, then rejected seasonal averaging anyway on cost-shift grounds. D.22-12-056 at 143. PG&E calls the resulting line item the Energy Export Credit.
Nine years, and it walks out with the customer
Start with the clock. It's the part nobody sells against. A NEM 2.0 customer keeps a twenty-year legacy period from Permission to Operate, then transitions automatically. The net billing tariff legacy period is nine years from the interconnection date, residential and nonresidential alike, and PG&E's Schedule NBT says it in those words.There's a second clock inside the first one. A complete interconnection application filed between April 15, 2023 and December 31, 2027 earns a locked nine-year schedule of hourly values, running from PTO. Schedule NBT draws those values from the Avoided Cost Calculator adopted as of January 1 of the year the complete application lands, so the filing date picks the vintage, and filing after the window gets you no locked schedule at all.
The residential adder rides the same nine years. ACC Plus was $0.02200 per kilowatt-hour for a 2023 vintage, steps down twenty percent a year, and lands at $0.00440 for 2027.
Here's the part that catches people. The legacy period and the lock-in attach to the customer who caused the system to be installed, not to the roof and not to the meter. A buyer of a house with panels inherits the hardware and none of the tariff, and Schedule NBT lists a Change of Party customer right there under the ACC Plus exclusions. The array conveys. The deal doesn't.
A salesman sold that array on midday export paying the loan. It generates what it was sold to generate. It earns a fraction of what it was sold to earn. The money moved to whichever hours the customer can shift load into, which is why the service upgrade shows up in the permit record before the array does.
The house said yes, fast
Berkeley Lab's October 2025 data update has the swing. California residential storage attachment on new PV went 14 percent in 2023 to 57 percent in 2024, while every other state combined moved 5 to 8 percent over the same period.Be careful what the decision promised. D.22-12-056 adopted a nine-year simple payback for stand-alone residential solar as the target, and $3.30 per watt as the 2023 cost of solar. Those are assumptions, not measured outcomes on your jobs.
California's median residential system in 2024 was 5.7 kW. The national median was 7.2 kW. Small roofs, expensive evening hours, and a tariff that pays you most for the power you never send anywhere. Some of those batteries have a second income now through grid programs, which is its own subject.
The warehouse roof went the other way
California non-residential storage attachment moved only 8 to 12 percent across those two years. The commercial battery has a different job. As of Berkeley Lab's July 2021 market review, most non-residential storage went in stand-alone rather than paired with PV.The warehouse owner was excluded from the glide path on purpose. Section 8.5.2 says commercial customers will not receive the ACC Plus, because their paybacks are shorter without it. PG&E's Schedule NBT lists Non-Residential third in the ACC Plus exclusions, under Change of Party customers. The one payback range on the record is the Commission's own, and it's 5.8 to 9.4 years.
Then the multi-meter properties lost the economics they were built around. Effective February 15, 2024, D.23-11-068 closed NEM2 load aggregation to new applicants and moved them onto NBTA, where imports and exports no longer net against each other. Special Condition 6 of Schedule NBT still lets a school, a farm or a warehouse campus run one array across several service points. The parcels have to be contiguous and under common ownership. What it stopped doing is netting.
SB 1374 would have required the Commission to restore account-level netting by July 1, 2025. The Governor returned it without signature on September 27, 2024, writing that it would compound the challenge of electric bill affordability.
The federal side pushes the same direction. Under 26 U.S.C. 48E(e)(4)(A) the credit doesn't apply to qualified property placed in service after December 31, 2027. P.L. 119-21 applies that termination only where construction began after July 4, 2026.
IRS Notice 2025-42 makes the Physical Work Test the sole method of establishing beginning of construction. Section 7 limits that to facilities whose construction had not begun before September 2, 2025, so anything already under way by then stays under the older beginning-of-construction notices, safe harbor included. Section 6 carves out a low output solar facility, meaning nameplate capacity in alternating current no greater than 1.5 MW.
Storage is carved out completely. 48E(e)(4)(C) exempts any energy storage technology placed in service at an applicable facility. Read those together and the warehouse sharpens toward a storage-weighted design.
The code is pushing the same way. California's 2022 Energy Code took effect for permit applications filed on or after January 1, 2023, and it prescribes PV on newly constructed nonresidential buildings where at least 80 percent of floor area is a listed occupancy, warehouse included. A building required to install PV under Section 140.10(a) also has to install battery storage sized per Equations 140.10-B and 140.10-C, subject to the exceptions in Section 140.10(b), and which of those your building lands in is a plan-check answer.
What the feeder will take
The queue is where these die. Guidehouse's March 2021 evaluation for the CPUC clocked SCE non-NEM projects at a mean of 122.7 business days from application to executed agreement or PTO, across 692 projects. Initial Review only projects ran 114.2 across 610 of them, and the 77 that fell into Supplemental Review took 181.9 business days to reach the same finish line. Sixty-eight extra business days because a screen said maybe.That's the argument I've made in a plan-check line. The spread underneath it doesn't hold it up.
DISTRIBUTION UPGRADES TRIGGERED, BY PROJECT SIZE (PG&E, 2021 CPUC EVALUATION, PERCENT OF PROJECTS) UNDER 30 KW 0.2 30 TO 100 KW 7.0 100 KW TO 1 MW 11.2 1 MW AND ABOVE 19.1
Under 30 kW, distribution upgrades triggered on 0.2 percent of PG&E projects. At 1 MW and above, 19.1 percent. Size decides whether an upgrade gets triggered at all. It does not decide duration, and Guidehouse says so directly: total time to an agreement or PTO varies by track, not by project size or technology. Projects 100 kW and up averaged 137.9 business days against 122.7 for everything, which is twelve percent on ten times the nameplate.
So the track is the whole story, and a design picks its own track. A designer sized that array to the roof instead of to the service. The screen it failed is published.
Fifteen percent of the maximum loading of the line section, counting the new generating facility and whatever generation already sits there. Above 1 MW the customer carries the triggered upgrades and the studies behind them, per Schedule NBT and Section 3.4 of SCE's interconnection handbook. There's also a 150 percent output-power ratio on paired storage above 10 kW AC, which got waived under D.20-06-017 and stayed waived past August 16, 2025 pending a further Commission decision. Size against it and you're designing to a limit nobody is enforcing this year.
The first two were knowable from the single-line, before the application went in. The screen caught a design problem early.
Price it as a calendar. SCE charges $94 to review a facility up to 1 MW and $800 above that line. Rule 21 gives the utility 10 business days to validate a clean application. Then 15 to complete Initial Review.
Supplemental Review is 30 business days, 10 for the customer to elect it and 20 for the utility to run it. A System Impact Study is 150 business days measured from Initial Review or 145 from Supplemental Review, and Guidehouse Table 14 carries both figures, which is the tell that they're branches and not a stack. Then it's 15 business days for a draft agreement and 90 calendar days for the customer to sign it. PTO typically issues 5 to 10 business days after the assigned engineer hands the project back.
The engineer who can tell you which branch you're on is reading your single-line against a line section you can't see from the roof. Bid the Solar & Battery work that's already cleared its service question. Watch the panel and service filings. Those land first, and they tell you what the feeder was willing to accept.