Undergrounding Frequently Asked Questions 

General Information                                                                                                    

What is the total length of above-ground power lines served by the electric investor-owned utilities?

California has approximately 25,526 miles of transmission lines, and approximately 239,557 miles of distribution lines, of which approximately 147,000 miles of distribution lines are overhead.

(Source: CPUC Undergrounding Program Webpage http://www.cpuc.ca.gov/General.aspx?id=4403)

Rule 20 Program                                                                                              

How do cities participate in Overhead Conversion Program? Is it the utility or the city that determines whether a city needs to convert overhead lines?

For Rule 20 Program, Cities identify overhead lines that they wish to convert to underground and in consultation with their investor owned utility (IOU) determine if the conversion project qualifies for any of the Rule 20 A, B, C or D programs.  If qualified utility ratepayer funds will cover between 0 and 100% of the costs of the conversion project as detailed below.

Communities interested in overhead conversion identify a project and work with the utility to determine whether it qualifies for utility funding.

  • Rule 20A: 100% utility funding

To be completely funded by the utility, a project must meet the public interest criteria (all aesthetic and traffic based) specified in Rule 20A. In addition, the community must also have accumulated enough Rule 20A work credit allocations. Such allocations are given out annually by the utility and communities can accumulate them over several years until they have sufficient funding to complete a project. The community identifies an overhead conversion project in consultation with the utility and then forms a utility underground district by municipal resolution to initiate a project.

  • Rule 20B and Rule 20C: Partial utility funding

Under Rule 20B, the community does not collect work credits for projects, but rather expends municipal funds and receives reimbursement after the project is completed for a small portion of the project costs 0-typically between 20 and 40% for Rule 20B and a de minimis amount for Rule 20C.

  • Rule 20D: Undergrounding for high fire risk areas (San Diego Gas & Electric (SDG&E) only)

Under SDG&E’s Rule 20D, communities receive 100% of utility funding for projects located within SDG&E’s High Fire Hazard Zone and mitigate fire risk and enhance reliability.

When and why was Rule 20D created and why is it limited to just SDG&E? Is this component of the program being explored for expansion to other electric IOUs in the existing undergrounding proceeding? 

SDG&E’s Rule 20D was authorized by the CPUC in February 20149. SDG&E developed Rule 20D largely in response to the 2007 Firestorm in Southern California that burned over 1.5 million acres. The Rule 20D program is intended to help reduce wildfire risk in cases where undergrounding is preferable to other system fire hardening measures. It is currently limited to SDG&E as only SDG&E applied to the CPUC for this specific tariff change to facilitate undergrounding conversions in fire-prone areas. The CPUC is currently considering various potential near-term improvements to Rule 20 as part of R.17-05-010, including whether Rule 20D should be expanded to jurisdictions outside of SDG&E’s Fire Threat Zone.10,11 

 Rule 20A Work Credit Allocations                                                                               

How are the credits allocated to each local government? Is it yearly? Is there a formula? Is one credit equal to $1? How many credits are local governments currently banking

The electric utilities annually allocate funds to each of the cities and unincorporated counties (collectively referred to as communities) that the utilities serve in their service territories. Yes, there is a formula and 50 percent of the work credit allocation is based on the proportion of overhead meters in the community to the total overhead meters in the service territory, and the other 50% is based on the total meters in the community (above and below ground) to the total meters in the service territory. Each work credit is equal to $1. The local governments across the state which are served by the investor-owned electric utilities currently have $950,627,101 collectively in unused funds that have been banked.

 

Which local governments have expended the highest amount of credits on projects over the last several years?

In the last several years, the local governments who used the highest level of work credits were primarily larger cities in the core economic, coastal regions of California such in as San Diego, San Francisco, Long Beach, and San Jose.  Among Pacific Gas and Electric (PG&E), San Diego Gas & Electric (SDG&E) and Southern California Edison (SCE), there are 252 communities that have either started or completed a Rule 20A project out of the 501 total communities that the utilities serve. The vast majority of these 252 communities have depleted or will deplete their work credit balances in the process of completing these projects as they need to accumulate work credits over many years in order to fund a project.

According to data from the electric utilities, the governments that have had the highest levels of Rule 20A work credit expenditures from 2005-2017 among these 252 cities and unincorporated counties are listed below: 

1.     The City and County of San Francisco: $174,194,533

2.     The City of San Diego: $123,959,969

3.     Unincorporated Los Angeles County: $80,199,098

4.     Unincorporated San Diego County: $66,219,539

5.     The City of Long Beach: $66,113,635

6.     The City of Oakland: $59,290,182

7.     The City of San Jose: $54,445,341

8.     Unincorporated San Bernardino County: $38,824,162

9.     The City of Fresno: $ 34,846,837

10.  The City of Chula Vista: $30,601,828

11.  Unincorporated Riverside County: $28,371,710

 

How long can the Rule 20A work credits go unused? Can local governments can bank their allotments or borrow for, at most, five years?

Under the current Electric Rule 20A Tariff, there is no limit to the number of years Rule 20A work credits can go unused. Local governments can bank their allotments indefinitely. Communities that require additional funds to complete a project can borrow forward up to five years of additional work credit allocations.

Can Rule 20A work credits accumulate indefinitely or could the CPUC redistribute them? Only for five years, correct?

Under the current Electric Rule 20A Tariff, there is no limit to the number of years a community may accumulate Rule 20A work credits. The CPUC can require the electric utilities to reallocate work credits only from communities that have been inactive in the program per Rule 20A. 

 

Underground Conversion Costs                                                                                   

What is the typical cost range for conversion of overhead electric lines to underground per mile?

According to PG&E, SCE and SDG&E, the costs for undergrounding overhead distribution infrastructure can range anywhere from $1.8 million to $6.1 million per mile. These costs represent all costs associated with the undergrounding effort: trenching, conduit, substructures, cabling and connections, meter panel modifications, cutover work, and finally removal from service of poles and wires.

Does the CPUC have any rules or verification protocols in place to determine if an electric investor-owned utility is providing “reasonable” cost of undergrounding estimates or do we defer to them?

The CPUC has jurisdiction over the utility’s overhead-to-underground conversion process for electric distribution infrastructure under Electric Tariff Rule 20. Under Rule 20B, the utility is granted the authority to charge applicants “a nonrefundable sum equal to the excess, if any, of the estimated costs, of completing the underground system.” The CPUC does not currently have any verification protocols in place to determine if electric IOUs provide “reasonable” cost estimates for the various components of individual undergrounding projects. Local governments are free to rely upon either their own in-house public works expertise or verification from third-party engineering firms to review PG&E’s cost estimates and agree on a reasonable range of costs.

If the municipal and local business applicants have reason to believe that the costs are unreasonable or unjustified, they have recourse at the CPUC via our Complaint process. However, the CPUC’s jurisdiction will be to ensure the utility is following the tariff language outlined in the Electric Tariff Rule 20. Let us know if you need additional information or input.

The PG&E Rule 20A Program Audit, conducted by AzP Consulting in compliance with D.18-03-022, uncovered several issues with PG&E’s management of Rule 20A. Among the various issues, the Audit found that relative to recognized nation-wide industry costs reported in the Edison Electric Institute’s (EEI) 2012 study on undergrounding, PG&E’s costs per converted mile were higher than the “maximum” conversion cost for two out of the three population densities – rural (50 or fewer customers per square mile) and suburban (51 to 149 customers per square mile). EEI’s suburban undergrounding costs range from $329,280 to $2,541,000 while PG&E’s average cost was reported to be $4,790,559. Similarly, EEI’s rural undergrounding costs ranged from $166,005 to $2,058,000 while PG&E’s average cost was $2,540,321. The Audit also found that PG&E did not perform any benchmarking studies from 2007 to present and PG&E did not provide any explanation as to why its costs were higher than nation-wide average undergrounding costs.

Is the cost to convert distribution lines spread across all of a utility’s ratepayers or specific to that city?

As noted above and detailed below:

  • Rule 20 A – 100% of cost spread across the utility’s ratepayers
  • Rule 20 B – 20-40% of costs spread across the utility’s ratepayers and remaining paid by the local city implementing the project.
  • Rule 20 C – The vast majority of costs are paid by the local city implementing the project.
  • City of San Diego Utility Undergrounding Program – 100% of the costs are paid by the electric ratepayers in the City of San Diego.  

As noted above, the utility costs for overhead conversion to underground facilities depends on the program and initiation of the project (i.e., the utility covers 100% of Rule 20A projects and 20-40% of Rule 20B projects).  Regardless of the percent of a project that is covered, any utility incurred costs for undergrounding are spread through electric rates across all electric customers.  The program costs are determined in the CPUC and reviewed and approved in a utility General Rate Case.  The methodology applied by utilities for sharing costs across customer types (commercial vs. residential, large vs. small, etc.) is determined in CPUC ratemaking proceedings. 

 

There are very few instances of city, county, or community rate components for any type of utility run program or utility costs. Therefore, the utility costs for undergrounding are not borne by a specific city. On the other hand, if a community funds overhead conversion under Rule 20B or C, the city’s own costs for the project are covered by the local municipality or the specific benefitting customers, depending on the project.

 

Fire Hardening                                                                                                            

Does the CPUC have any information that provides insight into how much undergrounding electrical equipment can reduce wildfire risk versus the “hardening” of such equipment?

Yes, Energy Division Staff has been referring to mitigation effectiveness data that In Southern California Edison (SCE) submitted to the CPUC in its current Grid Safety and Resiliency Program (GSRP) Application (A.)18-09-002.i In SCE’s Testimony in Support of its GSRP Application, SCE compares the costs and benefits between three different fire mitigation options for their overhead infrastructure located in the High Fire Threat District (HFTD):

1)    Re-conductoring and pole replacement with conventional wires and wooden poles

2)    Installing or re-conductoring and pole replacement with covered (insulated) conductors and fire-resistant metal poles

3)    Underground conversion of overhead infrastructure

SCE explains in its GSRP Testimony that through risk mitigation analysis it conducted, SCE determined mitigation effectiveness factors for all three of these wildfire mitigation options. SCE calculated the data in the following table which compares these mitigations:

SCE Mitigation Effectiveness-to-Cost Ratios for Undergrounding Alternatives

Mitigation Option

Relative Mitigation Effectiveness Factor*

Cost per Mile

Mitigation Effectiveness-to-Cost Ratio

Re-conductor -
Conventional poles and conductors

0.15

$300,000

0.5

Covered Conductors and Fire-Resistant Metal Poles

0.6

$480,000

1.4

Underground Conversion

1

$3,000,000

0.33

* Undergrounding serves as the baseline for measuring mitigation effectiveness.

According to SCE, a mitigation effectiveness factor could be interpreted as an estimate of the percentage of fires avoided with full deployment of the mitigation measure throughout SCE’s portion of the State’s High Fire Threat District, all else equal. Thus, full deployment of covered conductors and metal poles in the HFTD are estimated to mitigate approximately 60 percent of fires associated with SCE’s electrical distribution facilities in HFTD. Undergrounding theoretically would be able to mitigate 100 percent of such fires, all else equal. However, undergrounding conversion is over 6 times as expensive as covering the conductors and replacing wooden poles with fire resistant poles. As such, SCE asserts that installing covered conductors and metal poles has a mitigation benefit-to-cost ratio that is significantly higher than both undergrounding and conventional pole and wire replacement.

Can the electric investor owned utilities (IOUs) request funding as part of their Risk Assessment Mitigation Phase (RAMP) filings within their General Rate Cases to convert existing overhead electric system equipment to undergrounding if there is a compelling risk reduction reason for such an investment? Have any of the electric IOUs made such a request as part of their most recent RAMP filings?

Utilities may request funding within their General Rate Cases to convert existing overhead electric system equipment to undergrounding if there is a compelling risk reduction reason for such an investment.  RAMP filings do not include funding requests but can help inform the CPUC on the economic efficiency of various risk mitigation measures.

RAMP Example: Undergrounding of existing overhead lines was modeled as an alternative mitigation to reduce the risk of wildfires associated with overhead distribution facilities in PG&E’s 2017 RAMP Report.6 The report did not recommend this option because of its Risk Spend Efficiency (RSE) score. 

The Test Year 2020 PG&E GRC proposed a significant Overhead Line Harding Program for risk mitigation, but undergrounding is not a prominent feature of that funding request because of its higher cost to benefit ratio. 

 

In Southern California Edison’s Grid Safety and Resiliency Program Application they submitted in Fall 2018, are there any proposed categories to underground existing electric distribution equipment that potentially poses a risk to igniting wildfires?

No, Southern California Edison did not propose undergrounding of any existing overhead lines to mitigate wildfire risk in their Grid Safety and Resiliency Program (GSRP) Application. A large focus of the Edison application is fire hardening of their overhead infrastructure in their High Fire Threat District with covered conductors, which are powerlines covered in layers of tough plastic that prevent them sparking fires when they contact vegetation or other objects that come in contact with the wires. Many of the powerline segments that are slated to receive covered conductors will also have their wooden poles replaced with steel poles which are less susceptible to ignition.

Edison reports that the cost per mile for installing covered conductors and steel poles in Edison’s High Fire-Threat District is approximately $438,0007 while the cost per mile of undergrounding is approximately $3 million8. Thus, Edison concludes that investing in covered conductors is the most economical option for fire threat mitigation in their High Fire-Threat District. In Edison’s GSRP testimony, they state,

“A dollar spent reconductoring with covered conductor provides … over four times as much value in wildfire risk mitigation as a dollar spent on underground conversion.”

(Prepared Testimony in Support of Southern California Edison’s GSRP, page 54).  

In D.20-04-013, the CPUC approved nearly $285 million of the total $407.3 million approved for the GSRP for SCE’s Wildfire Covered Conductor program and will install covered conductors over 529 miles. D.20-04-023 did order a specific mileage of overhead lines for conversion in the GSRP.

 

Distribution and Service Line Extensions                                                                

Are all new building developments required to have electric distribution equipment undergrounded Do Tariff Rules 15 and 16 outline these rules and requirements?

This is correct for Rules 15 and 16, but there are certain instances in the Rules described below where the utility has the discretion to install equipment overhead. Electric Tariff Rule 15.A.3.a explains, “underground distribution line extensions are required for all new:

(1) Residential Subdivisions (except as provided for in Section H),

(2) Residential Developments,

(3) Commercial Developments,

(4) Industrial Developments, and

(5) Locations that are in proximity to and visible from designated Scenic Areas.”

According to Rule 15, the portion of the line that is to be converted underground is specified in Section A.2.b: “The length and normal route of a Distribution Line Extension will be determined by PG&E and considered as the distance along the shortest, most practical, available, and acceptable route which is clear of obstructions from PG&E's nearest permanent and available distribution facility to the point from which the service facilities will be connected.”2

Electric Tariff Rule 16 outlines the rules and requirements specifically for service facilities that extend from the utility’s distribution line facilities to homes or businesses. According to Rule 16.C.3.a, “underground service extensions:

(1) shall be installed where required to comply with applicable tariff schedules, laws, ordinances, or similar requirements of governmental authorities having jurisdiction, and

(2) may be necessary as determined by the utility where [the] Applicant's load requires a separate transformer installation of 75 kVa or greater.”3

Exemptions to Undergrounding Under Rules 15 and 16

Rule 15.H.1 details the types of locations in which the utility may construct overhead electric distribution extensions. According to Rule 15.H.1, “overhead extensions may be constructed in residential subdivisions or developments only where either a. or b. below are found to exist:

a. The lots within the residential subdivision or development existed as legally described parcels prior to May 5, 1970, and significant overhead lines exist within the subdivision or development.

b. The minimum parcel size within the new residential subdivision or real estate development, identifiable by a map filed with the local government authority, is three (3) acres and [the] Applicant for the distribution line extension shows that all of the following conditions exist.” 4,5 (The five conditions are listed in footnote four below for reference).

Rule 16.C.4 explains that new overhead service extensions may be permitted only in instances where Rule 16.C.3.a does not apply (see response to question #1 for the text of Rule 16.C.3.a).

For communities devasted by the wildfires, will those communities be subject to Tariff Rules 15 and 16? Meaning will any new electric distribution equipment be required to be undergrounded or will it be overhead electric distribution equipment?

No, it is not necessarily the case that any new electric distribution equipment will be required to be constructed underground even for communities devastated by wildfires. Some new electric distribution equipment may be installed overhead (see the response to the question above regarding Rules 15 and 16 (‘Are all new building developments are required to have electric distribution equipment undergrounded?”) for exemptions described in Rules 15.H.1 and 16.C.4).

   


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