Working With
the Utility

An owner planning new or expanded electric service will spend more calendar time interacting with one counterparty than with any equipment supplier, any engineer, and any lender. That counterparty is not a vendor and is not an adversary. It is a regulated monopoly delivering service under tariffs filed with the state, which means the terms of the relationship are published, the obligations are written down, and the recourse when they are not met is defined in advance. Very few owners read any of it before the project is late.

This paper is about that relationship as a working discipline. What the utility has actually committed to. What it has not. Where the published clock starts and who is holding it during each phase. Why adding load and adding generation are governed by different rulebooks with different queues and different dispute paths. And what an owner can do, in sequence, when a project stops moving.

The specifics below are drawn from California investor-owned utility tariffs and from decisions of the California Public Utilities Commission. The structure travels. The numbers do not, and an owner outside this territory should pull the equivalent documents for their own utility rather than borrow these.

Section 01Two clocks, one project

In September 2024 the Commission adopted a decision establishing target energization time periods for the three large electric investor-owned utilities. It implements two 2023 statutes and it does something the industry had not had before: it defines the energization process as eight discrete steps, assigns each step to the utility, the customer, or the authority having jurisdiction, and sets timing targets on the steps the utility controls.¹ The underlying statute defines the energization time period as the elapsed time beginning when the utility receives a substantially complete application and ending when the electric service is installed and energized.²

That framework created two clocks that owners routinely confuse. One measures the days the utility controls. The other measures the days between the application and the meter. They are not close to each other.

In the assessment of Pacific Gas and Electric Company's second biannual energization report, prepared by an independent third-party consultant and filed in November 2025, the reported figures for completed projects under the service line extension tariff were an average of 118 calendar days of utility-controlled time and an average of 307 calendar days end to end.³ For combined distribution and service line extension projects the figures were 117 and 389. For the electric vehicle infrastructure tariff they were 113 and 508.³

The gap is not evidence of bad faith, and it should not be read as one. It is a definitional result, and the definition is public. Under the reported methodology, when a customer phase overlaps a utility phase, the overlapping time is attributed entirely to customer time and not to the utility. When third-party activities such as land services, environmental review, encroachment permits or joint pole work run concurrently with a utility phase, that overlap is deducted from utility time as well. The consultant recalculated the figures under that methodology and expressly declined to comment on whether the methodology itself is appropriate.³

The practical consequence for an owner is simple and worth stating plainly. A utility can report high compliance against its adopted targets in the same period in which your project takes three times the target elapsed time, and both statements can be accurate. The reported share of completed projects finishing within the maximum on utility-controlled steps was 98.1 percent, 97.7 percent and 96.8 percent across the three tariff categories above.³ In the same reporting population, approximately 48 percent of applications submitted between January 31, 2023 and June 30, 2025 had been completed by June 30, 2025, so the reported averages describe less than half of the applications submitted in that window.³ Projects still in flight are not in the average.

Section 02What the published targets actually say

The adopted targets are stated in calendar days and are triggered by a customer energization request. They apply to the steps within the utility's control.¹

Where a request requires the grid itself to be reinforced, a separate set of maximums applies to the utility's planning and execution of the upgrade: 684 calendar days for a new or upgraded circuit, 1,021 for a substation upgrade, and 3,242 for a new substation.¹ Those are not typographical exaggerations. They are the adopted ceilings for the largest category of work, and the Commission stated it would continue evaluating the capacity upgrade process in a second phase of the proceeding.¹

Reported experience against the capacity numbers is worth knowing before a site is chosen. The same assessment reports 871 calendar days for completed new circuit and circuit upgrade work, 1,225 for substation upgrades, and an average of 487 days between the utility identifying the need for an upstream capacity project and service energization, across the sixteen energized customers in that population.³

Two cautions on all of the above. These are targets on utility-controlled steps, not contractual delivery dates, and nothing in the decision converts a target into a promise to any individual customer. And a target adopted in 2024 describes an expectation, not an outcome. Any owner making a capital commitment against these numbers should treat them as planning inputs to be re-verified, not as a schedule anyone has guaranteed. Bcal guarantees no timeline either, and no adviser who does should be believed.

Section 03Where the clock starts, and who is holding it

The clock starts at a substantially complete application. That single phrase moves more schedule than any other sentence in the framework, because a submission that is returned for correction has not started anything.

Of the eight steps, the utility is measured on engineering and design, its own permitting and regulatory dependencies, its site readiness inspections, construction, and final energization. The customer holds intake, customer dependencies, and site readiness. Customer dependencies is the phase that quietly consumes quarters: securing permits, paying fees, executing contracts and easements, and obtaining third-party approvals. Customer site readiness ends when the owner formally releases the site so utility construction can begin.^1,4

Utility guidance to customers under the new framework is explicit about this allocation and about the consequence. Customers are expected to engage early, submit a complete application, familiarize themselves with which party owns each step, and promptly provide required documentation, with the stated consequence that failure to do so will delay the project.⁴ The same guidance describes what the customer receives in return: a main point of contact through all stages of the process, milestone updates, and a published engagement plan.⁴

An owner reading that fairly should accept the implication. A meaningful share of the elapsed time on a stalled project is genuinely the owner's, and it is usually concentrated in documents nobody was assigned to chase. Before escalating anything, an owner should be able to state, with dates, which phase the project sits in and which party the framework assigns it to. That single exercise resolves a large fraction of perceived utility delays and it costs nothing.

Section 04Two rulebooks: adding load and adding generation

Owners considering on-site power often assume one application to one utility covers everything. It does not. Adding or upgrading load is governed by the line extension tariffs and the energization framework described above. Connecting a generating facility to the distribution system is governed by a different tariff, Rule 21, which sets the interconnection, operating and metering requirements for generating facilities and has its own study process, its own screens, its own agreements, and its own dispute procedure.^5,6

A site that is expanding and also intends to self-generate is frequently in both processes at once, with different reviewers, different documents, and different clocks. The sequencing between them is a real decision with real consequences. Applying for a large service upgrade the site may not ultimately need can trigger grid-side work and its associated cost responsibility. Applying only for generation, on the assumption that it will arrive in time to serve the new load, leaves the site with no fallback if the interconnection study returns an answer the owner did not expect. Neither error is recoverable quickly.

The honest position is that these are parallel options that should be carried in parallel until one of them is confirmed in writing, and that the cost of carrying both for a period is usually small against the cost of restarting either one. What that costs and how long the overlap should run is a site-specific judgment, not a rule.

Section 05The escalation ladder, in order

When a project genuinely stalls on the utility's side, there is a defined sequence. Using it out of order wastes the leverage each rung carries.

1. The assigned point of contact, in writingThe framework requires each utility to give customers a main point of contact and milestone updates. Use it, and put the substance in email rather than on calls, so the record builds itself. Most stalls resolve here because most stalls are a missing document or an unassigned queue item.
2. Formal notice under the tariffFor a generating facility, Rule 21 provides a written dispute notice stating the specific dispute and the relief sought. The receiving party acknowledges within five calendar days; each party designates a representative with decision authority within seven; the utility provides the relevant regulatory and technical detail and analysis behind the disputed requirement within twenty-one; and authorized representatives meet and confer within forty-five days of the notice. A copy of the notice goes to the Commission's Energy Division.⁵
3. The expedited variantThe same tariff offers expedited bilateral negotiations, invoked in the notice itself, compressing the technical response to ten business days and the meet-and-confer to fifteen business days from the date of the notice.⁵ Choosing the track is the aggrieved party's call, made at the moment of writing.
4. Extended negotiation or mediationIf forty-five calendar days pass without resolution, either party may request an additional forty-five days of negotiation, or both parties may jointly request mediation from the Commission's alternative dispute resolution program, administered by its administrative law judges. That program is voluntary, free, normally confidential, and most sessions run from half a day to two days. An outside mediator may be used instead, with costs shared.^5,7
5. The energization delay reportFor service requests, the Commission publishes a delay reporting form, submitted by email or mail to its Energy Division. Under the adopted decision, customers should submit it after seeking resolution with the utility or once the request exceeds the adopted maximum targets. Read the Commission's own caveat before relying on it: the form will not initiate a process to resolve an ongoing delay. It feeds data that informs future changes to the targets and to utility processes.⁸
6. Informal complaintThe Commission's Consumer Affairs Branch takes written complaints, evaluates them, and submits them to the utility as an informal complaint, with caseworkers working the facts between the parties.⁹ It is a genuine channel and it is also a queue. It is worth starting early rather than in the week the schedule breaks.
7. Formal complaintA formal complaint alleges that a utility violated the law, a Commission order, or its own tariff, and asks the Commission to order corrective action. There is no filing fee. A complaint that does not allege prior informal resolution may be referred back to staff to attempt one.⁷ This is a legal proceeding, and it should be entered with counsel and with a clear view of what it can and cannot deliver.

One further mechanism deserves mention with its current status attached. Legislation in 2016 authorized an expedited interconnection dispute resolution process issuing binding determinations within sixty days of an application, adopted by Commission resolution in 2017 and referenced in the tariff. The Commission's own page states the process has been temporarily suspended due to a lapse in funding, with disputes handled through informal staff dispute resolution in the interim.^5,6 An owner planning around a sixty-day binding determination should confirm the program's status on the day it matters rather than assume the tariff reference implies availability.

Section 06What the Commission can and cannot do for you

This is the part that changes how a sophisticated owner treats schedule risk, and it is stated plainly in the Commission's own published instructions.

The Commission can order a utility to take corrective action and can order reparations where service that was paid for was not provided. It is not permitted to award damages for things such as loss of profits.⁷ Compensation of that kind is a civil court matter, against a counterparty and a set of tariff protections that make such claims difficult.

The procedural shape matters too. The expedited complaint procedure is limited to disputed amounts under five thousand dollars for a corporation or other group, allows no attorneys on either side, and generally produces a hearing within thirty days of the utility's answer. The regular procedure covers any amount, permits attorneys, and carries no deadline for holding a hearing at all. The utility answers within thirty days, or twenty under the expedited track.⁷

Read those two paragraphs together and the conclusion is uncomfortable but useful. The regulatory route is well suited to compelling a utility to do the thing it was supposed to do. It is poorly suited to making an owner whole for a delayed production line, a missed lease commencement, or a customer commitment that could not be met. The remedy for schedule risk is not a complaint filed later. It is a decision made earlier, with the delay priced into the plan and an alternative carried far enough to be real.

Section 07Build the record before you need it

Owners tend to assume the utility's file will reconstruct the project's history if a dispute arises. The published evidence argues against that assumption, in a way that is entirely understandable and still consequential.

Of 8,923 completed projects in the reporting population, 310 had recorded start and end dates for all eight energization phases.³ Of the 747 projects initiated after the decision was adopted, 73 had complete phase-level data.³ The utility has stated that several date fields were not required to be captured before the decision, that missing historical dates cannot be recreated, and that new systems adopted in 2025 are expected to improve capture going forward.³ None of that is unusual for an operational data set that was never built to serve a regulatory metric. It does mean the definitive record of your project's timeline may be the one you keep.

What that record needs is unglamorous. The date the application was submitted and the date it was deemed substantially complete, which are different dates. Every document requested and the date it was provided. Every phase transition, named against the eight-step framework. Every commitment made verbally, confirmed the same day in an email that invites correction. Costs, estimates and revisions to estimates, with dates. Names and roles, because staff change over a multi-year project and the successor will not know what was agreed.

This costs an hour a month and it is the difference between a defensible position and a recollection.

Section 08The relationship is technology-neutral, and so is the constraint

Nothing in this process is avoided by choosing a particular generating technology, and any adviser who suggests otherwise is selling something.

A grid-only expansion avoids the interconnection tariff entirely and lives wholly inside the line extension and energization framework. That is a real advantage. It also concentrates all of the schedule risk in one place, on a clock the owner does not hold, with the capacity upgrade maximums above as the ceiling if the grid needs reinforcement.

On-site generation of any kind moves the site into the generation interconnection tariff as well. Reciprocating engines, gas turbines and microturbines, fuel cells, linear generators, and solar with or without storage all connect under the same rule, are screened by the same process, and can face the same requirement to fund distribution studies or upgrades. Their differences are real and they matter enormously for cost, emissions, fuel exposure and operations. Their differences do not include an exemption from the utility relationship. A storage-only project is in the generation tariff too, which surprises owners who think of storage as equipment rather than as a facility connected in parallel with the grid.

The case for and against each path is properly made on the site's own facts. The point here is narrower. Whichever path an owner takes, the same counterparty is on the other side of it, the same published clock applies to part of it, and the same escalation ladder is the only one available. That is an argument for treating the utility relationship as a managed workstream with an owner and a schedule, on equal footing with engineering and finance, rather than as an administrative task that happens between the interesting decisions.

Section 09Questions worth asking in the first month

The following are the questions that most often change a project's plan when they are asked early and most often produce an unwelcome surprise when they are asked late. None of them require a consultant to ask.

• Which tariff path is this request on, and if it is more than one, who is coordinating between them?
• What is the date the application was deemed substantially complete, and is that date recorded consistently by both parties?
• Which of the eight steps is the project in today, and which party does the framework assign it to?
• Does this request require grid-side capacity work, and if the answer is not yet known, when will it be known and what will be required to answer it?
• Who is the named point of contact, who is their supervisor, and what is the documented path when a step exceeds its target?
• What has the utility put in writing, as distinct from what has been said, and does the written record support the schedule the business is planning against?
• If this path takes the maximum published time rather than the average, what does the business do?

That last question is the one that separates a plan from a hope. It is also the question most easily deferred, usually until the calendar has already answered it.

Section 10The posture

The productive stance toward a regulated utility is neither deference nor hostility. It is precision.

Deference produces a project that waits politely through a phase nobody was working, because no one asked which phase it was in. Hostility produces a project that has escalated its way to the top of a ladder in month three, with nowhere left to go in month eighteen and a working relationship that has to be rebuilt with the same people who will handle the next request. Both are expensive.

Precision means knowing which document governs, which clock is running, which party holds the current step, what the published target for that step is, and what the next rung on the ladder is before it is needed. It is available to any owner willing to read the tariff. Most of it is published, most of it is free, and almost none of it is read before the schedule has already slipped.