PG&E's Gas and Electric Service Requirements — universally called the Green Book — is a 600-page standards document that governs how electric and gas service connects to every new development in PG&E territory. It covers meter placement, joint trench cross-sections, transformer pad dimensions, service extension cost allocation, and undergrounding rules. If you're building anything in Northern or Central California that needs power and gas, this document controls your utility timeline.

The problem is that nobody reads it until they're already behind schedule. And by then, the things it would have told you — that your Service Planning Request should have been filed six months ago, that transformer lead times have tripled, that your all-gas building design just lost its subsidy — are academic.

We coordinate dry utilities across California, Oregon, and Hawaii. PG&E territory is where we cut our teeth, and we've watched the Green Book's regulatory landscape shift more in the last two years than in the previous ten. This is the reference we wish someone had handed us before our first joint trench project.

Rules 15 and 16: Who Pays for Service Extensions (and Why It Just Got More Expensive)

Rules 15 and 16 are the tariff provisions that determine who pays for gas and electric line extensions to new developments. The basic framework: PG&E calculates a cost allowance based on projected revenue from your project, and the developer pays any costs exceeding that allowance.

For residential subdivisions, PG&E runs revenue projections per living unit. You submit a Service Planning Request with your project layout, their planners model the expected consumption, and they issue an allowance. If infrastructure costs exceed the allowance — and on a 50-lot subdivision 2,000 feet from existing primary feeders, the overage can run $200,000 to $400,000 — you write a check.

That's the framework that's been in place for decades. Here's what changed.

The Subsidy Elimination (July 2024)

Between 2018 and 2022, PG&E collected roughly $2.1 billion in line extension subsidies from ratepayers. Those subsidies reduced what developers paid to extend gas and electric service. As of July 1, 2024, that subsidy is gone for mixed-fuel projects — any development that includes both gas and electric service.

All-electric projects still receive allowances. Mixed-fuel projects don't. This isn't subtle. The CPUC deliberately tilted the economics toward electrification, and for developers still designing dual-fuel buildings, the cost impact is immediate and significant. We've seen line extension estimates jump 30 to 40 percent on projects that carried both gas and electric, simply because the allowance calculations changed.

If you're early enough in design to go all-electric, the math now strongly favors it — not because heat pumps got cheaper, but because PG&E's cost allocation changed underneath you.

Rule 20: Undergrounding Is Now Your Problem

Rule 20 is the undergrounding tariff. It has three tiers, and two of them just got worse for developers.

Rule 20A: The Free Money Is Gone

Rule 20A was the program developers loved — ratepayer-funded undergrounding of existing overhead utilities along public streets. Cities maintained allocation budgets from PG&E, nominated projects, and ratepayers paid.

No new Rule 20A credits have been allocated since 2022. Existing credits expired on June 8, 2025. The program formally sunsets in 2033, but functionally, it's over. If your project was counting on Rule 20A funds to underground overhead lines on an adjacent street, that money doesn't exist anymore.

Rule 20B: Credits With Conditions

Rule 20B is developer-initiated undergrounding where you pay the full cost but receive a credit equal to the cost of an equivalent overhead system — typically 20 to 25 percent of the total. You'll encounter this when your project fronts a street with existing overhead utilities and the city requires undergrounding as a condition of approval.

Rule 20C: You Pay Everything

Rule 20C is entirely developer-funded. No credit. No refund. This is the default for new subdivisions — you're installing brand new underground infrastructure, and you're paying for all of it minus whatever Rule 15/16 allowance applies. With Rule 20A dead, most undergrounding projects now land here.

SB 884 and Wildfire Undergrounding

Layered on top of Rule 20, SB 884 mandated that California's investor-owned utilities submit 10-year wildfire undergrounding plans. Conversion costs run $3 to $5 million per pole-mile. The CPUC added spending caps and audit requirements in December 2025, but the infrastructure demand is massive. For developers in fire-prone areas, this means PG&E's undergrounding crews and materials are being pulled toward wildfire zones. Your subdivision undergrounding project is competing for the same resources.

Joint Trench: The Coordination Gauntlet

Joint trench is a shared excavation — typically 48 inches wide and 42 inches deep for a standard four-utility configuration — carrying PG&E electric, PG&E gas, telephone (AT&T in most of California), and cable TV in a single trench. Each utility occupies a specific zone within the cross-section, separated by required clearances. The Green Book's Section 7 has the standard cross-sections.

The process starts with a Joint Trench Intent letter. It's a one-page form telling PG&E your project exists, how many lots or units it serves, and that you intend to install joint trench. It's not a design document. It's a handshake that triggers PG&E to assign a planner. Without it, your project is invisible to their system.

From there, coordination looks like this: you submit your Intent to PG&E, separately contact AT&T and your cable provider, and each utility produces their own design on their own base map with their own conventions at their own pace. Your job as the civil engineer is to combine all of it into one constructable set of plans. Nobody else is doing that synthesis. If you don't, it doesn't happen.

Composite Drawings: Where Three Designs Become One

The composite drawing is the most coordination-intensive sheet in a dry utility plan set. You're combining PG&E's electric design (transformer locations, switchgear, conduit routing), PG&E's gas design (main routing, service laterals), AT&T's design (pedestals, conduit, pull boxes), and cable TV's design (amplifiers, conduit) into a single plan view.

Each provider gives you their design in a different format, at a different scale, on a different timeline. Your composite has to reconcile all of it without conflicts — and it has to match the joint trench cross-sections at every point along the route. When the electric conduit shifts from one side of the trench to the other at a transformer pad, the cross-section changes. Your plans need to call that out.

On a 40-lot subdivision, that's 8 to 12 different cross-section conditions. On a phased project, double it. We show joint trench cross-section details at every change condition, because the contractor building this trench needs to know exactly what goes where at every station.

Will Serve Letters: What They Do and Don't Guarantee

A Will Serve letter from PG&E confirms they have capacity and are willing to serve your project. Cities require them for tentative map approval, and developers treat them like a guarantee.

They're not.

A Will Serve letter doesn't lock in a design. It doesn't lock in a cost estimate. It doesn't guarantee a timeline. It's a statement of intent, not a contract. We've seen projects where the Will Serve letter was issued for a 30-lot subdivision, the developer revised to 45 lots, and PG&E's cost estimate doubled because the load required a larger transformer and upgraded primary feeders.

Request the Will Serve letter early — most cities want it at the tentative map stage. Just don't confuse having one with having a design. And if your scope changes after the letter is issued, assume you're starting the conversation over.

Clearance Requirements: The Numbers That Govern Your Layout

These are the minimum separations the Green Book requires. Print this list, pin it to your wall, and hand a copy to your architect before they finalize their site plan:

On a tight site — affordable housing, urban infill, anything in San Francisco or downtown LA — these clearances are the puzzle pieces that determine your entire utility corridor layout. You don't design the road first and fit utilities in afterward. You design them together, or you redesign the road later.

The Timeline Reality: CPUC Numbers vs. Field Experience

The CPUC now publishes target timelines for PG&E service connections. Here's what they've established:

CPUC Service Connection Targets

Those are the targets. The field reality is uglier.

PG&E averages 64 days from construction completion to energization. SCE, by comparison, averages 9 days. Thirty percent of new buildings in PG&E territory wait 90 or more days after construction is done just to get power turned on. Eighteen months ago, PG&E's on-time energization rate was 5 percent. They've improved to roughly 50 percent and are targeting 80 percent, but if your project falls in the other half, you're carrying construction financing on a building that can't get a certificate of occupancy.

For a realistic planning timeline on a 30 to 50 lot subdivision, budget 4 to 8 months from Service Planning Request to construction-ready plans, then add PG&E's post-construction energization window on the back end. The developers who stay on schedule file their Service Planning Request the same month they submit their tentative map. The ones who wait until they have a grading permit? They're explaining to their investors why finished houses can't get power.

The Transformer Crisis

Even if you do everything right on the coordination side, there's a supply chain problem that no amount of planning can fully solve.

The U.S. currently faces a 30 percent deficit in power transformer supply and a 10 percent deficit in distribution transformers. Lead times for new transformers have stretched to 2.5 years. Prices are up 77 percent since 2019. A 50 percent copper tariff takes effect in August 2025, which will push prices higher. Industry analysts project transformer shortages continuing through the 2030s.

For developers, this means a few things. First, if your project requires a new transformer — and most subdivisions and large commercial projects do — that transformer is on a national backorder list. PG&E can design your service, approve your plans, and have your trench in the ground, and you'll still wait months for the physical transformer to arrive.

Second, the shortage has made PG&E more conservative about transformer sizing. They're less willing to oversize for future capacity because every transformer allocated to your project is one they can't use somewhere else. If your load calculation is borderline, push for the larger unit early. Upsizing later means going back to the end of the line.

EV Charging: The Service Sizing Earthquake

The 2025 California Green Building Standards Code (CalGreen), effective January 1, 2026, requires a dedicated branch circuit for every multifamily residential unit. Not EV-ready conduit. Not a shared charging station in the garage. A dedicated circuit per unit.

This changes electrical service sizing for multifamily projects in a way that most developers haven't internalized yet. Per-unit electrical demand roughly doubles when you add a Level 2 EV circuit to every apartment. Service panels that used to handle a 200-unit building now need to be sized for the electrical equivalent of a 400-unit building. Per-unit cost increases run $10,000 or more, and transformer sizing calculations based on pre-2026 load assumptions are no longer valid.

If you're designing a multifamily project in PG&E territory right now, your electrical engineer needs to be running load calcs against the 2025 code, not the 2022 code. And your civil engineer needs to be coordinating transformer sizing with PG&E based on those updated numbers. The old service sizing formulas don't apply anymore — we've seen projects where the EV charging load alone exceeded the building's original total service capacity.

What's Coming: 5G, Battery Storage, and the April 2026 Green Book

5G Small Cells

Small cell nodes for 5G wireless are adding a new coordination layer to joint trench design. Each node needs power and fiber, both of which may route through or adjacent to your joint trench corridor. The FCC has an open preemption proceeding on small cell deployment, but regardless of how that shakes out, the physical infrastructure needs a home in the right-of-way. On projects in San Diego and the Bay Area, we're already seeing telecom providers requesting conduit provisions for future small cell installations. It's one more thing to coordinate, and it's one more thing that didn't exist five years ago.

Battery Energy Storage Systems (BESS)

Title 24 2025 mandates battery storage for most nonresidential buildings with solar. From a civil engineering standpoint, that means a concrete pad, drainage, vehicle access for maintenance, and setbacks. The setback requirements are where it gets interesting: the California Fire Code baseline is 10 feet, but local jurisdictions are all over the map. Orange County requires 100 feet from occupied buildings for certain battery chemistries. We've seen 10 feet in one city and 100 feet in the next city over for the same battery system.

If your project includes BESS, confirm setback requirements with the local fire authority before you finalize your site plan. The pad location affects utility routing, and discovering a 100-foot setback after your dry utility plans are in review is a redesign you don't want.

The April 2026 Green Book Refresh

PG&E is publishing an updated Green Book in April 2026. If you're designing against current amendments, verify your standards assumptions at permit submission. We've been through enough Green Book revisions to know that cross-section details, transformer pad specifications, and clearance requirements can all shift between editions. Projects designed under one edition that submit for review under another create coordination headaches that take weeks to resolve.

What Developers Wish They Knew Before Starting

After 25 years of dry utility coordination — PG&E, SCE, SDG&E, Portland General, HECO — these are the lessons that keep repeating:

  1. File the Service Planning Request at tentative map, not at grading permit. PG&E's queue doesn't care about your construction start date. Every month you delay the SPR is a month added to your back end.
  2. Lock your site plan before PG&E starts design. Moving a building pad 10 feet shifts transformer locations, which shifts trench routing, which restarts PG&E's design clock. Every revision adds 4 to 8 weeks.
  3. Contact AT&T the same week you contact PG&E. AT&T's coordination is notoriously slow. If you don't initiate early and follow up relentlessly, you'll have PG&E's design in hand and no telecom design. Your composite drawing can't be completed without it.
  4. Don't assume the Will Serve letter means you have a design. It means PG&E is willing to serve you. The design, the cost, and the timeline are all still TBD.
  5. Budget for the transformer wait. Lead times are 2.5 years for power transformers. Your trench will be in the ground long before your transformer arrives. Plan your construction phasing around this reality.
  6. Run your load calcs against the 2025 code. EV charging requirements changed service sizing for every multifamily project. If your electrical engineer is using pre-2026 assumptions, your transformer is undersized before it's ordered.
  7. Pothole before you trench. A potholing program costs $5,000 to $15,000. Hitting an unmarked gas line during joint trench excavation costs $50,000 or more and a 3-month shutdown.
  8. Put the transformer on the site plan before the entry monument. The architect's decorative entry feature will lose every fight with PG&E's 8-foot front clearance requirement. Resolve transformer placement at schematic design, not at plan check.
  9. Watch for the April 2026 Green Book revision. If your project was designed against 2024 amendments, confirm your standards haven't shifted before submitting for review.

Dry utility coordination isn't the part of development that gets attention at the investor pitch or the city council hearing. It's the part that determines whether your finished building gets power on schedule or sits empty for three months while PG&E works through their backlog. The Green Book is the rulebook, and right now — with subsidies disappearing, transformers on backorder, and EV mandates rewriting service sizing — it's a rulebook that's changing faster than most project teams realize.

Get ahead of it, or it gets ahead of you.