Short answer: on February 5, 2026 the California Public Utilities Commission issued Decision 26-02-025, which orders Pacific Gas and Electric and Southern California Edison to build a standard, tariffed version of something they were already doing case by case. It lets a customer whose project is blocked by a distribution capacity constraint get energized now, at a capped level, while the grid upgrade proceeds behind them. It is optional, it only binds PG&E and SCE, and it does not move anyone up the queue. The piece that matters most to you is a safe harbor: load you put behind a certified power control system does not count against the utility’s capacity ratings.
What the Commission actually ordered
The decision is Decision 26-02-025, dated February 5, 2026 and issued February 10, 2026, in Rulemaking 24-01-018. Its title is “Decision Establishing a Standard Offer for Flexible Service Connections.”
The summary paragraph is the clearest statement of scope:
This decision directs Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (SCE) to establish a standard offer process within the Design and Engineering step of their energization process that establishes an optional Flexible Service Connection (FSC) agreement for customers affected by distribution capacity constraints.
This sits downstream of the Powering Up Californians Act, which is SB 410 and AB 50 from 2023. Phase 1 of the same rulemaking produced Decision 24-09-020 in September 2024, which set the eight standard energization steps and the average and maximum timelines the large utilities are measured against. This new decision fills a gap that Phase 1 left open: what happens when the answer is not “this will take a while” but “there is no capacity on that circuit yet.”
The order itself is short. PG&E and SCE were told to file a Tier 1 advice letter modifying their Tariff Rule 2 and Rule 3 language within 15 days of issuance, and a joint Tier 2 advice letter establishing the tariffed Standard Offering Flexible Service Connection Form Agreement within 60 days. A further Tier 2 advice letter formalizing their preliminary capacity assessment offerings was due no later than 75 days from issuance. The rulemaking remains open for Phase II.
Those filing windows all closed in the spring of 2026. Before you tell a customer this option exists on their specific job, confirm with the utility that the standard form agreement is actually in place and being offered in their area. The Commission set the deadlines for filing; it did not promise you a smooth counter experience on the other end.
What a flexible service connection actually is
The decision’s own definitions appendix is worth reading, because the vocabulary shows up on the paperwork.
A Flexible Service Connection is defined as “a means of energizing new load to a utility’s distribution system under specified import limits and operational conditions that vary over time.”
A Limited Load Profile, or LLP, is “a profile, or schedule, to be attached to service agreements governing energization of loads. It contains information on the maximum power that can be imported from the grid by the customer at any given time.”
Two more terms matter. Firm Capacity is “capacity that remains available as long as the FSCA remains in place.” A Static LLP is “an LLP that provides firm capacity. It is established and agreed upon at the time the FSCA is established and remains in place from year to year.”
Read those last two together, because they answer the question every customer asks. The standard offer is static and firm. It is a fixed schedule of caps agreed at the start, not a utility dispatching your customer’s equipment down in real time. The Commission was explicit earlier in the proceeding that these connections would be based on pre-programmed limited load profiles and would not use communications. The decision also directs that telemetry is not required, and that the load limit applies at the customer’s point of interconnection rather than behind the meter at the device level.
So the honest plain-English version for a customer is this: you can turn the equipment on now, and in exchange you agree not to pull more than an agreed number of kilowatts during agreed windows, until the upgrade is finished.
Who this actually binds
PG&E and SCE. That is the whole list.
The Commission declined to require the small multi-jurisdictional utilities to provide a standard offer, and SDG&E was not included in the directive either. Municipal utilities, including SMUD and LADWP, are not under CPUC jurisdiction at all, so this decision does nothing in their territory.
This is the first question to ask on a capacity-constrained job, and it is worth asking before you spend design time. The same customer conversation has a different ending depending on which utility serves the meter.
The safe harbor that changes what you install
This is the part with the most direct effect on your material list.
The Commission adopted a safe harbor for load under electronic control. In its words, “Safe harbor treatment means that controlled load behind a certified or approved Power Control System is not counted against the normal or emergency capacity ratings of IOU equipment.”
The specific finding goes further:
We find it reasonable that customer load installed under the control of a certified UL 3141 PCS shall not comprise an increase in connected or metered load provided that the UL 3141 PCS setpoint does not exceed the total amount of other connected or metered loads. We find that customer equipment installed within a UL 3141 PCS does not comprise a meaningful change in the amount or character of load for existing customers provided the customer stays within the previously authorized capacity.
The certification the Commission relied on is a power control system certified by a Nationally Recognized Testing Laboratory to the Power Import Limitation function in the second edition of UL 3141. The decision also requires PG&E and SCE to hand the customer their LLP values electronically in the format specified by UL 3141 Edition 2 Annex A.
If the equipment you need is not available with a certified UL 3141 PCS, you are not stuck. The Commission found the argument persuasive that customers should be able to use “other mutually agreeable solutions such as uncertified PCSs, software controls, Real-Time Automation Controllers (RTAC), and relays,” and allowed those to access safe harbor treatment where UL 3141 equipment “is unavailable or infeasible for the customer’s needs.” The tradeoff is that the utilities are permitted to require that uncertified power control systems successfully undergo system commissioning before that controlled load gets safe harbor treatment. Budget the commissioning visit if you go that route.
This is not unfamiliar equipment. In the 2023 NEC, which is the base for the California Electrical Code currently in force, the power control system provisions live in 750.30, with 220.70 covering the use of an energy management system to limit current on a feeder or service and 625.42 covering the EV supply equipment case. It is the same family of listed control you already reach for when you are trying to add load to a service without upsizing it. What is new is that the utility side now has a written rule saying that controlled load does not count against its equipment ratings.
Four things this does not do
It does not move your customer up the queue. The decision is explicit:
We clarify that customers utilizing a Standard Offer shall not have any change in their energization queue positions and that the IOU shall not change the prioritization of a capacity project based on customer participation in a Standard Offer.
That cuts both ways and you should say so out loud. Taking the flexible connection does not cost your customer their place in line, and it does not buy them a better one.
It does not guarantee eligibility. The decision requires the utilities’ application web pages to carry “A notice that not all customers will be eligible for FSC, and that final determination for eligibility is made by the utility.” The Commission specifically preserved the utilities’ ability to “curate the population of participating customers and decline FSCs where grid conditions or customer characteristics pose heightened risk.” Do not design around an approval you have not received.
It does not pay anyone. The Commission clarified during the proceeding that the standard offer would not address customer compensation and would not be used in the absence of constrained capacity. There is no incentive attached to accepting a cap.
It does not make the customer side free. The required web page content includes an “Estimation and description of customer side costs.” The control equipment, the design work, and any commissioning are the customer’s cost, and they belong in your bid as visible line items rather than absorbed into a panel price.
What the cap will actually look like
The Commission set a floor on how detailed the profile has to be, and the floor is coarser than a lot of parties wanted.
PG&E and SCE must specify the start and end dates for a minimum of three standard seasons, and offer a minimum of two daily values for each season. That is a minimum of six annual values. SCE was already doing exactly this, segmenting the year into three seasons with a full capacity period and a reduced capacity period in each. PG&E has taken a more bespoke approach, using time of day, a single static value, four seasons, or combinations, depending on grid conditions. Both are free to exceed the six-value minimum, and may provide a less granular profile if the customer asks for one.
Several parties pushed for 24 values. The Commission met them partway: where the utility has the technical capability, it must give the customer the option of requesting a 24-value LLP with two daily values for each of the 12 months. The cost of that request is borne by the requesting customer and “shall not exceed the anticipated labor cost of performing additional analysis.” PG&E and SCE have to track how many of those requests come in and how they turn out.
The practical read: six values is a blunt instrument. If your customer’s load is peaky, or the whole project depends on charging or running equipment in a narrow window, raise the granularity question during the iterative load limit discussion rather than after the agreement is signed.
How to work this into a bid
- Establish the utility before you design. PG&E or SCE means this option is on the table. SDG&E or a municipal utility means it is not.
- Ask for the preliminary capacity assessment early. The decision formalizes the process that lets a prospective customer evaluate the likelihood of suitable capacity at a location before committing. PG&E stated its preliminary capacity assessment is completed within 30 days. Getting that answer up front is the difference between a scoped job and a surprise.
- Expect different handling from each utility. The decision describes SCE’s existing approach as more directive, requiring SCE approval of both the equipment and the system design plus commissioning of the installed system, while PG&E has not imposed equipment requirements and uses metering data to flag excess use after the fact. The Commission noted that PG&E’s approach “has safely unlocked capacity at higher levels than SCE’s.”
- Put the control system in the bid as its own line. A UL 3141 listed PCS, its integration, and any required commissioning are real dollars. They are also the thing that makes the job possible at all, which is an easier conversation than it sounds.
- Do not quote a date for full capacity. You do not control the upgrade, and the queue is unchanged. Give the customer the cap and the process, not a calendar.
- Get the cap in writing to the customer. The customer is agreeing to a limit on how much power they can pull. If they blow through it and the utility’s first remediation step is customer education, the second conversation is less friendly. The decision preserved the utilities’ authority to enforce terms under their Electric Tariff Rules 11 and 14.
What to tell the person who calls
These calls do not arrive labeled. They arrive as “PG&E says I need an upgrade before I can put in the charger,” or a general contractor saying the service for a project is on hold, or a homeowner who was told a number of months and did not understand why.
The plain version is short. There may not be enough capacity on the local grid for the full load yet. The utility now has a standard option that can let the equipment run at a limited level while that gets fixed, and there is control equipment that makes the limit automatic instead of something anyone has to remember. It is not available everywhere, the utility decides who qualifies, and it does not change how long the upgrade itself takes.
What you actually need off that first call is narrow: which utility serves the address, what the new load is and what it is for, whether anyone has already applied or been given a capacity answer, and whether the customer could live with a cap during certain hours. Those four answers tell you whether you are looking at a normal service job or a capacity-constrained one, and that determines whether the site visit is a measurement or a negotiation. Sorting it on the phone is the difference between a bid you can stand behind and a truck roll that turns into a change order.
