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Selected Abbreviations Used in This Report

CPUC	California Public Utilities Commission
EPIC	Electric Program Investment Charge
PG&E	Pacific Gas and Electric
RAMP	Risk Assessment Mitigation Phase
SCE	Southern California Edison
SDG&E	San Diego Gas and Electric

Summary

Over the past decade, California has experienced some of its most devastating and costly wildfires. Utility‑caused fires are often more destructive than those resulting from other sources because many occur in remote areas during high wind events, and those same weather conditions cause the fire to spread quickly, making it difficult to control. Since 2015 power lines have caused six of the State’s 20 most destructive wildfires. Six investor‑owned utilities (utilities) that serve much of California are regulated by the California Public Utilities Commission (CPUC). In addition, the Office of Energy Infrastructure Safety (Energy Safety Office/office) within the Natural Resources Agency oversees and enforces utilities’ compliance with wildfire safety requirements. ¹ We use the term Energy Safety Office to refer to either the CPUC’s Wildfire Safety Division or the Office of Energy Infrastructure Safety depending on when actions occurred. The Legislature transferred all the functions of the Wildfire Safety Division to the Office of Energy Infrastructure Safety effective July 1, 2021. Thus, the actions we describe in the text that occurred prior to July 1, 2021, were taken by the Wildfire Safety Division and any actions that occurred after were taken by the Office of Energy Infrastructure Safety. It also approves wildfire mitigation plans (mitigation plans) that describe the strategies and programs a utility will adopt to minimize the risk of catastrophic wildfires caused by its electrical lines and equipment. One of these strategies is the use of public safety power shutoffs (power shutoffs), which utilities have used to prevent fires when strong winds, low humidity, and related conditions are present. However, doing so leaves communities and essential facilities without power, imposing hardships and increased risks, including the inability of the disabled and others to rely on electric‑powered devices and life support equipment.

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Utilities Will Need to Make Further Improvements to the Electrical Grid to Reduce the Risk of Wildfires and to Prevent Power Shutoffs and Unplanned Outages

California is at a higher risk of wildfires and more frequent power shutoffs in part because of the nearly 40,000 miles of bare power lines in areas where there is a greater threat of wildfire. In 2020 the six utilities reported completing hardening projects—improvements to make electrical equipment more fire resistant or to reduce the risk of them igniting a fire—on only 1,540 miles of lines. The cost of making the improvements on all 40,000 miles of bare power lines in high fire‑threat areas is generally significant, and because these costs are included in the utilities’ rates, could pose a substantial burden to ratepayers.

In January 2022, a new state law (shutoff reduction law) began requiring that utilities identify circuits—sections of power lines within a utility’s electrical grid—that have been subject to frequent power shutoffs, and the improvements the utilities have already taken or plan to take to reduce the need for and impact of future power shutoffs. According to CPUC data, there were 67 power shutoffs from 2013 through 2021, de‑energizing thousands of circuits across California and affecting more than 3.6 million customers. The shutoff reduction law could be strengthened by requiring that utilities identify the improvements that are necessary to prevent future power shutoffs on those circuits, such as moving power lines underground. This law could also be amended to address a type of power outage that is occurring more frequently. Specifically, some utilities have altered settings on equipment that have resulted in unplanned outages. Although taking such action may prevent wildfires, one utility’s alteration of electrical equipment settings caused hundreds of unplanned power outages from July through November 2021 with no advance notice. Despite the adverse impacts these outages cause, the Energy Safety Office does not consider the requirements of the shutoff reduction law to apply to this type of outage and thus, it has not issued guidelines regarding utilities use of them.

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The Energy Safety Office Awarded Safety Certifications to Utilities Despite Serious Deficiencies in Their Mitigation Plans

The Energy Safety Office must issue safety certifications to utilities that demonstrate they meet certain criteria established in law—such as having an approved mitigation plan. These safety certifications affect requirements for utilities to repay certain amounts to a fund they can use to help pay for the costs of wildfires they cause. The Energy Safety Office issued the 2020 safety certifications to the three largest utilities, even though it identified serious deficiencies in each of their mitigation plans. Although for 2021 the Energy Safety Office no longer approved mitigation plans without the utility first addressing critical issues, we question the appropriateness of the process it followed to approve mitigation plans and issue the 2020 safety certifications. In addition, the law does not allow the Energy Safety Office to deny a safety certification based on a utility’s failure to implement a prior mitigation plan—state law requires the Energy Safety Office to consider whether a utility is in the process of implementing its most recently approved mitigation plan when issuing a safety certification. Thus, whether a utility has previously implemented its mitigation plan has no bearing on the office’s decision to issue its safety certification.

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The Energy Safety Office’s Mitigation Plan Approval Process and the CPUC’s Audit Process Do Not Hold Utilities Sufficiently Accountable

The Energy Safety Office approved utilities’ mitigation plans despite some utilities’ failure to demonstrate that they are appropriately prioritizing their mitigation activities. As referenced earlier, utilities reported that their hardening projects had addressed relatively few miles of bare power lines in high fire‑threat areas during 2020. However, we found that the Energy Safety Office approved mitigation plans that did not provide adequate information on how utilities prioritized those projects. For example, the office conditionally approved Pacific Gas and Electric’s (PG&E’s) 2020 mitigation plan in June 2020 even though it found that PG&E had not described where vegetation management—trimming trees and vegetation from around power lines—was most necessary. Further, a court‑established Federal Monitor found that PG&E had conducted a certain type of vegetation management in relatively low‑risk portions of its power grid instead of in high fire‑threat areas and had not conducted planned inspections of some equipment in its highest threat areas.Nevertheless, the Energy Safety Office guidelines for 2022 mitigation plans do not require that the utilities clearly delineate in their plans where mitigation activities will occur. As a result of this weakness, the Energy Safety Office does not assess whether utilities plan to conduct these mitigation activities in areas of highest risk for wildfire as a condition for approving their mitigation plans.

Moreover, the CPUC conducts audits to determine whether utilities are in compliance with rules designed to ensure that they are operating safely, but those audits could be improved to better ensure such compliance, thereby helping mitigate the risk of utility‑caused wildfires. Specifically, the CPUC does not consistently audit all areas in the utilities’ service territories, it did not audit several areas that include high fire-threat areas, and it does not use its authority to penalize utilities when its audits uncover violations.

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Introduction

Background

Over the past decade, California has experienced some of its most devastating and costly wildfires. There are three elements required to start a fire: fuel (such as dry vegetation), oxygen, and heat (an ignition source). According to the state fire marshal, wildfires are inevitable throughout most of California. However, some ignition sources, such as vegetation contacting power lines and causing sparks, are preventable. Further, a California Department of Forestry and Fire Protection (Cal Fire) assistant deputy director stated that fires caused by utilities (utility‑caused fires) are often more destructive than those resulting from other sources because many utility‑caused fires occur in remote areas during high‑wind events—bringing branches, trees, or debris in contact with power lines and sparking fires—which cause the fires to spread rapidly. A 2020 California Public Utilities Commission (CPUC) report also noted that a growing population in areas where human development meets combustible wildland vegetation results in more communities exposed to wildfire risk and in more electrical infrastructure being built in wildfire‑prone areas—where downed power lines may come into contact with fuels, or objects such as trees may come into contact with power lines, potentially generating sparks that ignite wildfires.

Addressing preventable ignition sources has become critical as wildfires have grown larger and more destructive. As Figure 1 shows, eight of the 10 largest California wildfires have occurred during the past five years, including the 2017 Thomas Fire and the 2021 Dixie Fire, which were both caused by utilities. According to Cal Fire, fires caused by electrical power—such as electrical power distribution or transmission equipment—accounted for about 10 percent of all wildfires in the areas for which it has responsibility each year from 2016 through 2020, as Table 1 shows. Once the fire starts, the same weather conditions that contribute to electrical power‑caused fires—the most critical of which is high wind—also cause the fire to spread rapidly and make it difficult to control. Since 2015 power lines have caused six of the State’s 20 most destructive wildfires. The State’s fourth climate change assessment report issued in 2018 indicates that under a scenario in which changes do not occur to reduce emissions, by 2100 the average area burned by wildfires in California will increase by 63 percent.

Figure 1

Utilities Caused Two of the 10 Largest Wildfires in California From 1932 Through 2021

Table 1

Wildfires Caused by Electrical Power Account for 19 Percent of Cal Fire‑Reported Acres Burned 2016 Through 2020

WILDFIRES			Wildfires Caused by Electrical Power
Year	Total wildfires	Total acres burned	Number	Percent	Acres burned	Percent
2016	2,816	245,000	270	10%	3,000	1%
2017	3,470	467,000	408	12	250,000	54
2018	3,504	1,063,000	297	8	247,000	23
2019	3,086	130,000	304	10	84,000	65
2020	3,501	1,459,000	335	10	59,000	4
Totals	16,377	3,364,000	1,614	10%	643,000	19%

Not only has average wildfire size and the area burned annually increased, the cost of combating the fires has grown. From fiscal years 2016–17 through 2020–21, the State’s annual expenditures for Cal Fire—the state agency responsible for providing fire protection and prevention—nearly doubled, from $1.9 billion to an estimated $3.5 billion. According to the National Interagency Fire Center database for large wildfires and other significant events, as of December 2021 California’s large fires in that year cost $2.6 billion to suppress—accounting for more than half of the $4.3 billion of such costs reported nationally. In addition, these data show that the total cost of suppressing large wildfires in California from 2015 through 2021 was more than $9.1 billion.

Wildfires result in many additional costs beyond the cost of suppressing them. A 2018 research report, funded in part by the U.S. Forest Service, described both short‑term wildfire costs—such as those for suppressing the fire, evacuation services, relief aid, and home and property losses—and longer‑term damage—such as habitat restoration, business losses, and medical costs, including those associated with exposure to smoke. This research estimated that suppression costs represent only 9 percent of total wildfire costs. The other costs of wildfires have been significant, and not all of them are financial costs. In the last six years, California wildfires have killed nearly 200 people and damaged or destroyed more than 53,000 structures. The California Natural Resources Agency’s communications director indicated that the State does not regularly track or estimate the cost of wildfires in a way that accounts for public health costs or ecological damage. Other research has attempted to estimate these costs. For example, researchers from several international universities conducted an analysis of California’s 2018 wildfires that suggests that the economic impact of wildfires may be significantly larger than the cost of suppressing them and may affect economic activities in areas beyond the location of the physical destruction or smoke. That analysis calculated suppression costs for California’s 17 largest wildfires in 2018 to be nearly $1 billion but estimated that the damage totaled $149 billion, including destroyed and damaged buildings and infrastructure, health costs, and economic losses.

In a 2020 report, the CPUC’s Wildfire Safety Division recognized that the threat of wildfire is increasing and that utility‑related ignitions are responsible for a “disproportionate” share of wildfire‑related consequences. According to a 2019 report from a gubernatorial strike force, more than a quarter of California’s population—about 11 million people—live in areas where human development meets combustible wildland vegetation, known as the wildland‑urban interface, and there are an estimated 4.5 million homes in that interface. The number of people living in the interface will continue to rise if nationwide trends continue. Further, there is significant overlap between the wildland‑urban interface and the areas the CPUC considers high fire‑threat areas.

Oversight of the State’s Electrical Grid

The electrical grid is a network of components, including transmission and distribution lines (power lines), substations, and transformers. Power plants generate electricity, but electricity must have a path, or circuit, in order to travel to homes and businesses where it is used. Generally, there are two classifications of power lines carrying electricity from one location to another. High‑voltage transmission lines, such as those that hang between tall metal towers, carry electricity over long distances. Higher voltage electricity is more efficient and less expensive for long‑distance electricity transmission than lower voltage. Transformers at substations reduce the voltages from long‑distance transmission lines before electricity is transferred to the distribution lines that carry it to homes and businesses. Several types of entities provide electricity in California, including publicly owned utilities, rural electric cooperatives, and investor‑owned utilities. Investor‑owned utilities (utilities) are privately owned utilities whose stock is publicly traded. Six such utilities serve much of California, as Figure 2 shows. ² Our use of the term utilities in this report refers to a subset known as electrical corporations. State law requires utilities to provide adequate, efficient, just, and reasonable service, and the Legislature considers electricity essential to the health, safety, and economic well‑being of all California consumers.

Figure 2

Investor‑Owned Electric Utilities Served Most of the State in 2020

The CPUC has the authority to regulate utilities. Through a process known as a general rate case, described in more detail below, the CPUC approves utility cost and spending plans in the first phase of the process, which are the basis for the rates utilities charge consumers that it approves in the second phase of the process. The Governor appoints and the Senate approves the CPUC’s five commissioners (the Commission), and a portion of the CPUC’s revenue comes from fees it imposes on utilities. The CPUC is responsible for implementing and enforcing standards for the maintenance and operation of facilities that generate electricity that are owned by a utility or located in the State. The CPUC has also stated that it is responsible for ensuring that the utilities it regulates are providing service and facilities that do not constitute a threat to the public or the environment. For fiscal year 2020–21, it spent nearly $740 million and had a staff of 581 employees responsible for its regulatory function, as Table 2 shows. The scope of the CPUC’s oversight is significant given the size of the entities it oversees. The six utilities collectively employed more than 47,000 individuals and had revenues of nearly $43 billion in 2020. The CPUC also regulates privately owned communications, natural gas, and water companies, in addition to overseeing railroad and rail transit, moving, and transportation companies.

Table 2

Electric Utility Regulation Is a Small Portion of the CPUC's Total Expenditures

	CPUC Regulatory Expenditures
FISCAL YEAR	Total CPUC Staff Positions	Total Regulatory Expenditures	Regulatory expenditures FOR electric utilities*	Percent of Regulatory Expenditures FOR Electric Utilities
2016–17	432	$671,000,000	$57,000,000	8%
2017–18	419	598,000,000	59,000,000	10
2018–19	411	717,000,000	72,000,000	10
2019–20	496	837,000,000	130,000,000	16
2020–21	581	737,000,000	101,000,000	14

The CPUC approves the rates that utilities can charge for electricity every four years. Through the general rate case process—which is overseen by a commissioner and CPUC’s administrative law judges—the utilities request the CPUC’s approval for rate changes based on the revenue required to pay for their operating expenses and capital costs (revenue requirement). According to the CPUC, utilities may also request additional revenues and rate changes in between general rate cases, in some circumstances. The revenue requirement consists of a number of factors, such as the utility’s normal business expenses, depreciation, and taxes; and it is the basis for designing the rates consumers are charged. Since 2015 the CPUC has required California’s large utilities—Pacific Gas and Electric Company (PG&E), San Diego Gas and Electric Company (SDG&E), and Southern California Edison Company (SCE)—to file a Risk Assessment Mitigation Phase (RAMP) proceeding in advance of their general rate cases. A RAMP proceeding examines a utility’s assessment of its key risks, including those posed by wildfires, and its proposals for mitigating those risks, and the CPUC requires the utility to incorporate the results of its RAMP proceeding into its general rate case.

The CPUC is also responsible for ensuring the protection and safety of utility customers at large, and it exercises its regulatory authority in part by issuing General Orders that govern the activity of multiple utilities under its jurisdiction. A General Order has the force and effect of law, and its violation may result in penalties. To ensure that utilities are following the construction, maintenance, and inspection requirements outlined in its General Orders, the CPUC performs audits of the utilities. It also investigates certain wildfires, including those caused by utilities, to assess utilities’ compliance with applicable rules and regulations. To oversee and enforce utilities’ compliance with wildfire safety requirements, the Legislature required the CPUC to create the Wildfire Safety Division by January 1, 2020. The Legislature also established the Office of Energy Infrastructure Safety (Energy Safety Office/office) within the California Natural Resources Agency and, effective July 1, 2021, transferred the activities of the CPUC’s Wildfire Safety Division to that office, as Figure 3 shows. Because the director, the staff, and the activities of the Wildfire Safety Division were transferred to the Energy Safety Office, for the purposes of this report, we use the term Energy Safety Office to refer to both the newly formed Office of Energy Infrastructure Safety and the Wildfire Safety Division that previously existed as a part of the CPUC.

Figure 3

State Law Shifted Certain Activities From the CPUC to the Office of Energy Infrastructure Safety

The Energy Safety Office is a relatively small organization, with only 30 employees as of January 2022. State law assigns it the responsibility for reviewing and approving utilities’ wildfire mitigation plans (mitigation plans) and overseeing utilities’ compliance with approved mitigation plans. Among other things, mitigation plans describe the preventive strategies and programs a utility will adopt to minimize the risk that its electrical lines and equipment will cause catastrophic wildfires. The Energy Safety Office is also responsible for issuing safety certifications to utilities that meet certain requirements outlined in state law. Safety certifications affect the amount utilities must reimburse the Wildfire Fund in certain situations—described in more detail below—which is intended to provide electrical corporations that are safe actors a mechanism to guard against the financial effects of wildfires that is more cost‑effective than traditional insurance.

The Legislature established the Wildfire Fund in 2019 to pay for certain claims against utilities for damages due to wildfires they cause, to support the creditworthiness of utilities, and to reduce the cost to ratepayers in addressing utility‑caused catastrophic wildfires. The Wildfire Fund is funded through a loan from the State’s surplus money investment fund, contributions from participating utilities, and surcharges on some of the utilities’ ratepayers, with a goal of ultimately reaching a claim‑paying capacity of approximately $21 billion. Each large utility—PG&E, SCE, and SDG&E—participates in the Wildfire Fund, and according to the Wildfire Fund administrator, the balance was nearly $11 billion as of December 2021.

Participating utilities may seek payment from the Wildfire Fund to satisfy third‑party claims for covered wildfires that exceed the greater of $1 billion in any year or the amount of insurance the utility must maintain. State law requires participating utilities to maintain reasonable insurance coverage, the amount of which the fund administrator must periodically review and recommend. In general, utilities must reimburse the fund for costs that the CPUC determines are not just and reasonable. By law, utilities with a valid safety certification for the period in which the wildfire ignited are presumed to have acted reasonably, and if the CPUC determines the costs for which they claim reimbursement are not just and reasonable, the amount the utility must reimburse the Wildfire Fund is capped.

However, if the CPUC determines that the utility’s costs were not reasonable and it did not have a safety certification or the fund administrator determines that its actions or inactions constituted a conscious or willful disregard of the rights and safety of others, the utility must reimburse the Wildfire Fund in full. As of December 2021, none of the participating utilities had made a claim on the Wildfire Fund. However, in a quarterly report to the Securities and Exchange Commission, PG&E indicated that to the extent liabilities related to the 2021 Dixie Fire exceeded $1 billion, it was eligible to make a claim to cover the excess amount, and that as of September 2021, it had recorded an accounting entry for probable recoveries of $150 million from the Wildfire Fund in connection with that fire.

Power Shutoffs Can Be Effective in Preventing Potential Wildfire Ignitions During Certain Conditions

State law declares that reliable electric service is of utmost importance to the safety, health, and welfare of the State’s citizenry and economy. However, in a 2012 decision, the CPUC concluded that utilities have the authority under state law to proactively shut off electric power to customers when it is necessary to protect public safety. Such actions are known as public safety power shutoffs (power shutoffs). Utilities use these power shutoffs when they deem it necessary for public safety, such as to prevent fires when strong winds, low humidity, and related conditions are present. However, doing so leaves consumers, communities, and essential facilities, such as hospitals and fire departments, without power from the electrical grid, thereby imposing increased risks and hardships.

In an effort to better prepare the public and local officials for power shutoffs, the Commission adopted a resolution in 2018 to, among other things, increase communication and notify customers as soon as practicable before the power shutoff and to require utilities to submit a post‑event report to the CPUC within 10 days after each shutoff. From 2019 through 2021, the Commission expanded the power shutoff guidelines that utilities must follow. For example, a utility must now include in its post‑event report the alternatives it considered before it initiated the power shutoff. The CPUC also requires that a utility report on how it determined that the benefits of a power shutoff outweighed potential public safety risks and use a power shutoff only as a mitigation measure of last resort.

All three large utilities (PG&E, SCE, and SDG&E) noted in their 2021 mitigation plan updates that power shutoffs are a necessary fire prevention mechanism of last resort. All six of the utilities describe power shutoffs in their mitigation plans and four of them have implemented power shutoffs in the past. The decision to de‑energize electric facilities for public safety depends on several factors, including the dryness of vegetation near power lines and local weather conditions, such as wind speed and humidity. Extended droughts, extreme wind events, and the relative dryness of the surrounding vegetation—among other things—can propagate large wildfires. 

As the State’s risk of wildfire has increased, power shutoffs have proven effective at preventing possible ignitions resulting from broken equipment and hazards during high wind conditions, such as tree limbs blown onto power lines. After a utility concludes a power shutoff, the CPUC requires the utility to submit a post‑event report that details, among other things, any wind‑related damage to overhead power lines where power was shut off. Our review of 15 such reports found that 11 of them described wind‑related damage, including vegetation in direct contact with power lines and damage to electrical equipment, such as broken power poles, that might have ignited a wildfire had the power not been shut off. In two of these reports, the utilities indicated there were more than a hundred instances of wind‑related damage to equipment. Until utilities make improvements to power lines to withstand such weather conditions without the risk of igniting a wildfire, de‑energizing power lines will continue to be a necessary mitigation tool to protect the public.

Although they prevent wildfires, power shutoffs can have a number of adverse effects. As Appendix B shows, during 2019 and 2020, individual power shutoffs affected anywhere from fewer than 20 people to more than 940,000. Power shutoffs affect public safety in a variety of ways, as the text box shows. Further, they can be very costly. A 2019 SCE study surveyed customers to collect detailed information on the costs that they incur during power outages. The study found that the costs varied based on the length of the outage, but it estimated that the average cost to residential and small or medium business customers were $0.07 and nearly $21 per minute of the power outage, respectively, which SCE stated generally aligned with those of a 2012 PG&E study. Based on these figures, a power shutoff lasting 10 hours would cost a residential customer $42 and a small or medium business $12,600. A February 2021 report published by the Lawrence Berkeley National Laboratory that cited the SCE study, described limitations of outage data collected through surveys, such as SCE’s study, including possible biases, and consequences and costs that the respondent does not consider. Although SCE’s estimates may not be the most precise measure of all outage‑related costs, the cost of the 62 power shutoffs for which there was duration information was more than $21 billion in total—based on the SCE average cost estimates for residential and small or medium business customers. The majority of those costs are the result of two PG&E outages in 2019 with costs that totaled more than $14 billion. In its 2020 utility wildfire mitigation strategy, the Energy Safety Office emphasized that the State’s leadership and residents view the magnitude of past years’ power shutoff events as unacceptable and that utilities must minimize the need to use power shutoffs as a wildfire mitigation tool.

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Utilities Will Need to Make Further Improvements to the Electrical Grid to Reduce the Risk of Wildfires and to Prevent Power Shutoffs and Unplanned Outages

Key Points

• There is a higher risk of wildfires and power shutoffs in California in part because of the nearly 40,000 miles of bare power lines in areas with a greater threat of wildfires. In 2020 the six utilities reported hardening projects—improvements to make electrical equipment more fire resistant or to reduce the risk of equipment igniting a fire—on only 1,540 miles of lines.
• In January 2022, a new state law began requiring utilities to identify circuits in their mitigation plans that have been frequently de‑energized during power shutoffs and to identify the measures, such as moving power lines underground, that the utilities have taken or plan to take to reduce the need for and impact of future power shutoffs. The Legislature could better ensure that utilities are taking adequate steps to reduce the need for power shutoffs by requiring that utilities’ mitigation plans also identify the improvements necessary not only to reduce the scope, but to prevent power shutoffs on the circuits routinely affected by them.
• The three largest utilities have altered settings on their equipment, which resulted in hundreds of unplanned power outages with no advance notice to customers. However, unlike planned power shutoffs, the Energy Safety Office does not currently require utilities to identify in their mitigation plans the power lines that are frequently experiencing these unplanned outages and improvements to reduce their impact.

Implementing Improvements, Such as Installing Covered Power Lines and Managing Vegetation, Can Reduce the Risk of Wildfires and the Need for Power Shutoffs

A 2020 Energy Safety Office report stated that the impact of power shutoffs on safety and climate change goals is intolerable, indicating that it is not a long‑term solution to mitigating the risk of wildfires. ³  The report stated that utilities’ mitigation activities should also advance climate change goals, such as limiting diesel generator usage during power shutoffs. However, operating portions of the electrical grid in certain weather conditions increases the risk of utility‑caused wildfires. In some circumstances, the risk of a catastrophic wildfire in certain areas is so high that utilities determine there is no alternative to turning off the electricity. Thus, all three of the large utilities continue to rely on power shutoffs as a method of last resort to prevent wildfires. According to CPUC data, there were 67 power shutoffs from 2013 through 2021, de‑energizing thousands of circuits—sections of power lines within a utility’s electrical grid—across California and affecting more than 3.6 million customers. The CPUC publishes a fire threat map that designates significant portions of the State to be at an elevated or extreme risk of fire, as Figure 4, shows which we refer to collectively as high fire‑threat areas. The utilities reported information for 57 power shutoffs, and all of them occurred in, or partially in, high fire‑threat areas. Those individuals who were affected lost power for 37 hours on average, and some shutoffs involved repeatedly de‑energizing the same section of power lines. Further, the CPUC’s power shutoff data indicate that from 2017 through 2021, utilities de‑energized approximately 270 circuits during three or more different power shutoffs in the same calendar year.

Figure 4

Large Areas of California Are at Elevated or Extreme Risk of Utility-Caused Wildfires

One significant aspect of the electrical grid that contributes to the need for power shutoffs is the number of miles of bare power lines in high fire‑threat areas. Nearly 27 percent—more than 74,000 miles of the nearly 277,000 miles of the six utilities’ power lines—are located in these areas. The utilities collectively reported that at least 54 percent of these power lines are bare lines, as Table 3 shows. Notably, PG&E accounted for the vast majority of these bare lines—more than 33,000 of the nearly 40,000 miles of bare power lines among utilities in the State. Further, 80 percent of PG&E’s power lines in high fire‑threat areas are bare.

Table 3

At Least 54 Percent of the Distribution Power Lines in High Fire‑Threat Areas Are Bare

Bare lines are of particular concern because nearly half of the fire incidents that utilities reported from 2015 through 2020 were caused by power lines coming into contact with foreign objects, including vegetation. The three largest utilities’ data on certain ignitions they caused from 2015 through 2020 reveal that power lines themselves accounted for at least 74 percent of ignitions, not including ignitions caused by transformers, fuses, and poles. ⁴ A 2014 CPUC decision requires only PG&E, SDG&E, and SCE to collect and report these fire‑incident data. Figure 5 shows the locations of 3,550 utility‑caused ignitions reported by utilities from 2015 through 2020. An SCE study found that bare power lines are much less effective than other types of power lines at preventing certain types of faults, or abnormal electrical currents, that can lead to ignitions—such as those caused by vegetation contact, which SCE considers one of the highest risks for causing wildfires.  ⁵ In 2018 SCE compiled a comprehensive review of the research, benchmarking, engineering analysis, and testing to evaluate the effectiveness of covered lines used in the development of its application for its grid safety and resiliency program. Although only some of the ignitions shown in Figure 5 caused a large wildfire, these are the general types of ignitions that have resulted in catastrophic utility‑caused wildfires.

Figure 5

There Were 3,550 Utility‑Caused Fire Incidents Reported by the Three Largest Utilities From 2015 Through 2020

To reduce the risk of utility‑caused wildfires and the need for power shutoffs to prevent these types of wildfires, utilities must make improvements to the electrical grid to reduce the likelihood that electrical equipment will cause a fire. For example, at least three of the utilities have altered their power shutoff protocols for areas where they have installed covered power lines to allow for higher wind speeds before resorting to a power shutoff. Installing covered power lines—wires sheathed in a plastic covering that provides an insulating effect—and other mitigation efforts, including burying power lines underground and trimming trees and vegetation from around power lines, have been found to reduce the risk of utility‑caused ignitions. According to SCE’s 2021 mitigation plan update, making such grid‑hardening improvements is one of the most—if not the most—important mitigations that SCE can deploy to reduce power shutoffs. However, data that utilities reported to the Energy Safety Office identified that only 27 percent of the power lines in high fire‑threat areas are underground or covered. For example, although the land around Arrowhead Lake is in a high fire‑threat area, Figure 6 shows that many of its power lines are bare, other, or unknown. Figure 6 also shows a summary by county of the percentage of power lines that five of the utilities reported are underground or covered.

Figure 6

The Percentage of Utilities’ Distribution Lines That Were Underground or Covered as of June 2021 Varied by Location

Trimming and removing trees and other vegetation to maintain a minimum distance from power lines, known as vegetation management, is another important strategy that can help reduce the risk of utility‑caused wildfires and the need for power shutoffs. Cal Fire’s reports on the wildfire incidents it responded to within its direct protection area from 2018 through 2020 indicate that on average, fires caused by vegetation contact accounted for 74 percent of all acres burned by electrical power‑caused wildfires. ⁶  A direct protection area is the area for which a particular fire protection organization has primary responsibility by law or contract for attacking an uncontrolled fire and directing suppression activities. In some instances, high winds blow vegetation into bare power lines, causing sparks that lead to fires. A CPUC General Order requires utilities to keep areas near power lines clear of vegetation, as Figure 7 shows. In some cases, utilities conduct enhanced vegetation management exceeding the standard vegetation management requirements. For example, one utility reported that it planned to go beyond the CPUC minimum standards and perform enhanced vegetation management on its distribution lines in elevated and extreme fire‑threat districts to the standard shown in the right‑hand image in Figure 7. A PG&E analysis of 414 historical ignitions from 2015 through 2017 found that a combination of enhanced vegetation management and system hardening, including installing covered power lines and other improvements, would have mitigated nearly 80 percent of those ignitions. Further, from 2015 through 2020, at least 24 percent of the reportable ignitions the three largest utilities reported were caused by vegetation coming into contact with utility equipment.

Figure 7

Vegetation Management Consists of Clearing Vegetation Within a Certain Distance of Power Lines

Despite the important benefits that vegetation management provides, at least one utility has failed to perform it sufficiently. According to a November 2021 report on PG&E from the Federal Monitor—an entity originally established by a federal court to prevent the criminal conduct that gave rise to the 2010 San Bruno gas explosion and also assigned the responsibility of assessing PG&E’s wildfire mitigation and wildfire safety work—PG&E’s routine and enhanced vegetation management work could be improved. For example, PG&E’s enhanced vegetation management, which it plans to perform on all circuits in high fire‑threat districts, is being performed so slowly that it will take more than 10 years to complete. In 2020 a federal judge found that PG&E had diverted funds from work projects, including vegetation management, for bigger employee bonuses, shareholder dividends, and political contributions, among other things. According to a federal court, the primary cause of wildfires ignited by PG&E were hazardous trees and limbs that should have been, by law, removed. In its September 2020 quarterly report on its mitigation plan, PG&E itself stated that vegetation‑caused ignitions are one of the largest drivers of utility‑caused wildfires and that vegetation that is not actively managed can come into physical contact with utility equipment year‑round, creating additional ignition opportunities.

Although moving power lines underground is considered one of the best ways to reduce the risk of utility‑caused wildfires, that approach is generally expensive to implement. According to the U. S. Energy Information Administration, buried power lines are protected from the wind, ice, and tree damage, so they are subject to fewer weather or vegetation‑related outages. However, the U.S. Energy Information Administration also notes that the cost of underground power lines is significant—up to five to 10 times more than overhead distribution lines—and that converting existing overhead power lines to underground lines includes the added cost of dismantling the overhead system. For example, SDG&E and PG&E estimated that moving power lines underground costs approximately $2.6 million and $3 million per mile, respectively. Costs for moving power lines underground also vary by location. A report prepared by the Edison Electric Institute found that the cost of moving power lines underground ranged from $93,000 per mile in rural areas to $5 million per mile in urban areas.

Installing covered power lines is another mitigation activity that can reduce the risk of wildfire and power shutoffs. Figure 8 shows the difference between bare and covered power lines. According to the U.S. Department of Energy and the Institute of Electrical and Electronics Engineers, covered power lines are very effective in preventing potential ignitions resulting from foreign objects that come in contact with traditional bare power lines under high‑wind conditions. Moreover, an SCE study found that each dollar spent replacing existing bare power lines with covered lines provided four times as much value in wildfire risk mitigation as a dollar spent on converting the bare lines to underground power lines.

Figure 8

Some Power Lines Are Covered With an Insulating Material to Protect Them From Contact With Other Objects

Despite the risk posed by bare lines, the geographic data and quarterly reports that utilities submitted to the Energy Safety Office indicated that their hardening initiatives have addressed only a relatively small number of the miles of bare power lines in high fire‑threat areas. From July 2020 to June 2021, the geographic data the six utilities collectively reported indicate that they completed 628 miles of hardening projects—projects that involve physically manipulating electrical equipment to make it more fire‑resistant or to reduce the risk of igniting a fire. The Energy Safety Office’s data manager stated that it relies on separate quarterly initiative reports that utilities submit to the Energy Safety Office that summarize their progress in completing the goals enumerated in their mitigation plans. Those reports also show that utilities’ hardening projects addressed relatively few miles of the bare power lines in high fire‑threat areas. Utilities report on a variety of hardening projects, some of which measure progress by the number of poles inspected or trees removed, rather than in miles of line. However, according to the Energy Safety Office, the 2020 fourth‑quarter initiative reports indicate that of the initiatives that are measured in miles, the utilities reported performing hardening on only 1,540 miles of power lines in 2020. Even if all of these hardening projects consisted of replacing bare lines in high fire‑threat areas with covered power lines or moving them underground, the utilities would have addressed only 4 percent of the nearly 40,000 miles of bare power lines in areas of elevated or extreme fire risk.

Installing Certain Equipment Can Reduce the Impact of Power Shutoffs but Does Not Fully Prevent Future Shutoffs From Occurring

Effective January 2022, a new state law requires that utilities’ mitigation plans identify circuits that have frequently been de‑energized and the measures the utilities have taken or plan to take to reduce the need for and impact of future de‑energization of those circuits (shutoff reduction law). The shutoff reduction law also requires utilities to estimate their annual decline in circuit de‑energization. As part of its 2022 mitigation plan update guidelines, the Energy Safety Office is requiring utilities to include in their plans a list of each circuit that was de‑energized to mitigate the risk of wildfires three or more times in a calendar year and the measures the utility has taken, or plans to take, to reduce the need for and impact of future power shutoffs of that circuit. There are various types of improvements that utilities can make to reduce the scope and impact of power shutoffs, including installing microgrids and sectionalizing devices.

State law defines a microgrid, in part, as an interconnected system of sources of energy and energy demands with clearly defined electrical boundaries that can connect to, disconnect from, or run in parallel with, larger portions of the electrical grid. Thus, some microgrids can be disconnected from the electrical grid and operate autonomously to maintain the electrical supply to the critical infrastructure connected to it during power shutoffs. Figure 9 illustrates how a microgrid is able to disconnect from the electrical grid and rely on local power resources and storage to provide electricity for critical services. For example, PG&E installed temporary microgrids that provided electricity for crucial services during at least five power shutoffs in 2020 and 2021. In another instance, a microgrid that received funding through the CPUC’s Electric Program Investment Charge (EPIC) program allowed the continued provision of power to approximately 10,000 people in Humboldt County during a 2019 PG&E power shutoff.

The CPUC established the EPIC program in December 2011 to fund public investments in microgrids and other technologies, tools, and strategies that benefit electricity ratepayers. Reports on EPIC‑funded microgrids published by the California Energy Commission, which helps administer the program, indicate that they reduced the scope and impact of electric outages and resulted in economic benefits. According to the CPUC, the EPIC program has funded at least 23 microgrid‑related projects since 2015. The cost of installing microgrids can vary. For example, EPIC‑funded microgrid projects ranged in cost from $1.2 million to more than $9 million.

Figure 9

Microgrids Can Allow the Continued Provision of Electricity for Critical Services When an Area Is Disconnected From the Larger Electrical Grid

Sectionalizing devices can also limit the scope of a power shutoff event. For the purpose of this report, we define sectionalizing devices as equipment that allows utilities to turn off power to smaller segments of the electrical grid and reduce the impact of a de‑energization event. Figure 10 shows how sectionalizing devices, in conjunction with reclosers or automatic circuit breakers, can help reduce the number of customers affected by a power shutoff event by limiting its extent. Reclosers and circuit breakers are types of equipment that allow utilities to interrupt power at the point they are located within a circuit. The three largest utilities installed approximately 1,000 sectionalizing devices from 2019 through 2020, and they rely on these devices to reduce the extent of power shutoffs and to help minimize the number of customers impacted by them. Both PG&E and SDG&E also indicated that they plan to install additional sectionalizing devices by the end of 2022.

Figure 10

Sectionalizers Allow Utilities to Turn Off Smaller Portions of the Grid, Which Can Reduce the Scope and Impact of Power Shutoffs

Although microgrids and sectionalizing devices can reduce the impact of power shutoffs and the number of customers affected, they do not fully eliminate the need for future power shutoffs if weather conditions occur that are similar to those that triggered the earlier power shutoffs. To prevent the need for power shutoffs, utilities must make improvements, such as installing covered power lines or moving them underground to increase power lines’ resilience in high‑wind conditions and reduce the likelihood of the power lines igniting a wildfire.

The Legislature Should Strengthen the Shutoff Reduction Law to Require That Utilities Identify Measures Necessary to Prevent Power Shutoffs

The cost of making the improvements necessary to prevent power shutoffs throughout the State, such as installing covered power lines or moving lines underground, is generally significant and could pose a burden to ratepayers. Although utilities report that installing covered lines is generally cheaper than placing them underground, it may well cost billions of dollars to address bare power lines in high fire‑threat areas. Based on the amounts the three largest utilities reported spending to install covered power lines in 2020, it cost about $700,000 per line mile on average. Using this figure, the cost of replacing the nearly 40,000 miles of bare lines utilities reported in areas of elevated and extreme fire risk would be $28 billion. The CPUC’s Public Advocates Office and other stakeholders have raised concerns about the cost‑effectiveness of installing covered power lines when utilities have proposed such programs because portions of certain utility proposals were not located in the highest‑risk portions of the electrical grid. For example, The Utility Reform Network—a nonprofit consumer advocacy organization—argued in 2019 that SCE’s general rate case for 2021, 2022, and 2023 was unaffordable and recommended that SCE focus on its highest‑risk segments and reduce its budget for installing covered power lines from $2.7 billion to $643 million.

Although the shutoff reduction law requires utilities to identify circuits that have been routinely de‑energized to mitigate the risk of wildfires, the law could be strengthened by requiring that utilities identify specific improvements that are necessary to prevent future power shutoffs. To implement the shutoff reduction law, the Energy Safety Office requires utilities’ 2022 mitigation plans to map and list frequently de‑energized circuits and list the measures they have taken or will take to reduce the need for and impact of future de‑energization of those circuits. Its director stated that the Energy Safety Office will determine what next steps are necessary after it evaluates how well utilities plan to reduce the scope and frequency of the power shutoffs described in their 2022 mitigation plans.

Although such planned reductions in the scope and frequency of power shutoffs may represent an improvement, any power shutoff generally imposes risks and hardships. Further, if the Energy Safety Office is to minimize the need to use power shutoffs as a wildfire mitigation tool and meet its stated objective of pursuing wildfire mitigation activities that do not significantly impact electric utility reliability, it will need to ensure that utilities make improvements to the electrical grid that eliminate the need for power shutoffs in the weather conditions that have led to their routine use in the past. The Legislature could better ensure that utilities are taking adequate steps to reduce the need for power shutoffs by requiring that utilities’ mitigation plans also identify the improvements necessary not only to reduce the scope, but also to prevent power shutoffs on the circuits routinely affected by them if the conditions leading to those shutoffs were to occur again.

The number and cost of improvements utilities will need to make is not known, in part because the shutoff reduction law took effect in January 2022. Further, the shutoff reduction law does not require utilities to estimate the cost of future improvements to circuits that are frequently de‑energized. The significant cost of making improvements necessary to prevent the need for power shutoffs, such as installing covered power lines or moving them underground, may be one of the reasons why the improvements have not yet been made. However, even if these improvements cost billions of dollars, SCE’s estimates of customers’ costs during power shutoffs indicate that power shutoffs have cost more than $21 billion to date, as discussed earlier.

Utilities’ Alteration of Power‑Line Settings Have Resulted in Hundreds of Unplanned Power Outages, Affecting More Than a Half Million Customers

The three largest utilities have altered settings on their equipment, including circuit breakers and reclosers, resulting in unplanned power outages (unplanned outages) throughout the State. When there is excessive current flowing in a circuit—which could be caused by an object like a tree blown over in high winds making contact with an energized line—a circuit breaker or recloser automatically interrupts power to the circuit. Typically, after a preset duration, a recloser restores the power to determine whether the fault still exists and interrupts power again if it does. The recloser repeats this sequence a set number of times, and if it continues to detect the fault, it will de‑energize the line. However, utilities are able to change settings on some breakers and reclosers so that they turn off the power more quickly if there is an issue on an energized line. PG&E stated that adjusting these settings in 2021 to turn electricity off more quickly resulted in an approximate 46 percent reduction in ignitions in high fire‑threat areas compared to the three‑year historical average.

Although those actions may have effectively prevented wildfires, PG&E’s alteration of breaker and recloser settings in 2021, known as enhanced powerline safety settings (power‑line settings program), also triggered hundreds of unplanned outages that affected more than a half million customers. PG&E stated that in July 2021, it altered these settings along 11,500 miles of power lines located in high fire‑threat areas. From late July through early November 2021, its power‑line settings program resulted in nearly 600 unplanned outages that affected more than 650,000 customers. These outages occurred with no advance notice, affected an average of more than 1,000 customers per outage, and averaged more than 17.5 hours per customer in duration. The CPUC indicates these outages are more than a matter of inconvenience—they are disruptive, and for customers who rely on electricity to maintain necessary life functions, they can be life‑threatening. However, unlike a planned shutoff, customers and public safety partners receive no warning of these outages before their power is interrupted.

According to the CPUC’s website, all six utilities will include altering settings on their equipment (power‑line setting measures) in their 2022 mitigation plans, and both PG&E and SDG&E have already indicated that they plan to use these settings in the future, resulting in more unplanned outages. Although some utilities reported reductions in the extent and duration of proactive power shutoffs in 2020 and anticipated further reductions in 2021, this decrease may be related to the additional use of power‑line setting measures that more frequently trigger unplanned outages for customers. For instance, although PG&E expects to see further reductions in the scope of proactive power shutoffs, according to the CPUC’s wildfire safety enforcement branch program manager, PG&E indicated to the CPUC that it anticipates expanding the power‑line settings program in 2022.

Despite the hundreds of unplanned outages and more than a half million customers affected by PG&E’s use of the power‑line settings program in 2021, the Energy Safety Office does not consider power‑line settings programs to fall under the definition of a de‑energization event as described in the shutoff reduction law. Thus, the office does not require utilities’ mitigation plans to identify the circuits that are frequently experiencing these unplanned outages or the measures the utilities have taken or plan to take to reduce the need for and impact of unplanned outages in the future. The Energy Safety Office’s director indicated that the office may issue guidelines regarding utilities’ use of the program in the future. However, the unplanned outages due to the power‑line settings program that are caused by power lines contacting vegetation are the result of the same situations that power shutoffs are intended to prevent. Until utilities make improvements to those power lines that are routinely de‑energized because they have altered settings on their equipment, it is likely that customers will continue to be subject to additional unplanned outages in coming years.

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The Energy Safety Office Awarded Safety Certifications to Utilities Despite Serious Deficiencies in Their Mitigation Plans

Key Points

• The Energy Safety Office issued safety certifications even though it identified deficiencies in utilities’ mitigation plans.
• Further, state law does not require the Energy Safety Office to ensure that utilities have implemented prior mitigation plans before they are issued safety certifications.

Our review of the 2020 safety certifications issued to PG&E, SCE, and SDG&E found weaknesses in the Energy Safety Office’s process for issuing them. ⁷ As we discuss in the Introduction, we use the term Energy Safety Office to refer to either the CPUC’s Wildfire Safety Division or the Office of Energy Infrastructure Safety depending on when actions occurred. The Legislature transferred all the functions of the Wildfire Safety Division to the Office of Energy Infrastructure Safety effective July 1, 2021. Thus, the actions we describe in the text that occurred prior to July 1, 2021, were taken by the Wildfire Safety Division and any actions that occurred after were taken by the Office of Energy Infrastructure Safety. As we discuss in the Introduction, the office must issue safety certifications to utilities that demonstrate they meet certain criteria established in statute. Having an approved mitigation plan—which identifies the activities the utility intends to undertake to mitigate wildfire risks—is one of these legal requirements. However, the office identified significant deficiencies in the 2020 mitigation plans that PG&E, SCE, and SDG&E submitted. Specifically, it determined that each utility’s plan had one or more Class A deficiencies—the most serious type of deficiency—which it describes as an aspect of the mitigation plan that is lacking or flawed. For example, the office determined that all three plans failed to demonstrate how they were using risk modeling to inform decision making, and thus they could not demonstrate that they were targeting the highest‑risk portions of the electrical grid. Nonetheless, the Energy Safety Office issued a conditional approval of the mitigation plans for all three of these utilities we reviewed. Conditional approval is a term not defined in the statute pertaining to mitigation plans, yet as we describe below, the office treated it as an approval. As a part of the conditional approval, the office required utilities to file remedial plans to resolve the deficiencies it had identified. However, the office found that all of the three utilities’ remedial plans were insufficient.

Although the Energy Safety Office identified significant concerns with each of the three large utilities’ 2020 mitigation plans, it approved the plans through its conditional approval process and issued safety certifications to the utilities. The director of the office stated that for the 2020 mitigation plans approved while she was director of the Wildfire Safety Division, a conditional approval constituted approval pursuant to state law, and that although the utilities were required to submit remedial plans, its analysis of these plans was not a condition of its approval. As we discuss later, the office revised its mitigation plan review process for 2021 mitigation plans and now requires utilities to address critical issues before it approves their plans. However, the office’s own definition of the deficiencies it identified as mitigation plan aspects that are lacking or flawed, and its revision of its approval process, calls into question the appropriateness of the process it followed to approve mitigation plans and issue safety certifications for 2020.

Even if the Energy Safety Office’s process for issuing safety certifications had not included conditional approvals, the requirements in state law are insufficient to assure that utilities that are issued certifications have implemented their mitigation plans. The bill establishing the requirements for safety certifications describes how the Wildfire Fund will support the credit worthiness of electrical corporations. It also describes how utilities must invest in hardening electrical infrastructure and performing vegetation management, and that a safety certification encourages utilities to invest in safety and improve safety culture to limit wildfire risks. However, the state law does not allow the Energy Safety Office to deny a safety certification on the basis that a utility did not implement a prior mitigation plan.

As the text box shows, state law requires that the Energy Safety Office issue a safety certification to a utility that meets a number of requirements, including demonstrating that it is implementing its approved mitigation plan and submitting quarterly notifications about implementation. State law does not include the utility’s implementation of a prior year’s plan as criteria for issuance of the safety certification. It does require the office to issue a safety certification if a utility is implementing its most recently approved mitigation plan, among other things. However, the implementation of the plan is occurring in the same time frame as the safety certification determination. The Energy Safety Office’s director stated that the compliance period for a mitigation plan is defined as the calendar year in which the plan was filed, and a utility must be afforded the full compliance period to determine whether it has substantially implemented its plan. Because the rate at which a utility completes initiatives varies throughout the year, the director also stated that the Energy Safety Office does not expect a utility to accomplish an equal 25 percent in each quarter of the work it plans to complete.

Further, the Energy Safety Office's final assessment of whether a utility has implemented its mitigation plan does not occur until well after the safety certificate expires. As the example in Figure 11 shows, the office is not required to make a determination of whether the utility complied with its mitigation plan during calendar year 2020 until September 2022—more than eight months after the end of the period for which the 2020 safety certification was valid. Therefore, whether a utility substantially implements the projects in its mitigation plan has no bearing on the issuance of its safety certification as a result of these two factors: first, because the implementation of the plan is in progress, the Energy Safety Office performs only a limited review of whether a utility is implementing its current mitigation plan, and second, determinations of whether a utility substantially implemented its prior mitigation plans are not one of the criteria established in law for it to assess when issuing a safety certification.

Figure 11

Energy Safety Does Not Determine Whether a Utility Has Implemented Its Mitigation Plan Until After Issuing Its Safety Certification

The Energy Safety Office’s inability to deny a safety certification based on poor implementation of prior mitigation plans led it to issue a safety certification to PG&E despite concerns about PG&E’s progress in mitigating wildfire risks. In October 2020, before the office issued PG&E’s 2020 safety certification, the Federal Monitor concluded that it strongly appeared that PG&E had failed to adhere to its risk models when executing its wildfire risk reduction work. Specifically, the Federal Monitor noted that PG&E had completed the majority of its 2019 enhanced vegetation work in relatively low‑risk portions of its high fire‑threat areas, and it had performed approximately 1,000 inspections of transmission towers outside of high‑threat areas, but it had not conducted any of its planned enhanced inspections of transmission structures in its highest‑threat areas. The office noted these concerns in the issuance letter for PG&E’s safety certification but nonetheless stated that PG&E had met the minimum statutory requirements for issuance of a safety certification.

Although the office’s director stated that if the law were amended to require that the office consider completed compliance assessments of previous mitigation plans, it could incorporate the assessments into the process, she nonetheless expressed concern that it would change the statutory intent of the safety certification. Specifically, she noted that the certification is currently designed to encourage utilities to invest in safety and improve their safety cultures to limit wildfire risks and reduce costs, but it was not designed to be retrospective or punitive. Although we agree that the law establishing the Wildfire Fund describes the intent of the safety certification in this manner and that its focus is directed to utilities that are safe actors, it is unclear how issuing safety certifications to utilities that fail to implement their mitigation plans furthers this intent.

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The Energy Safety Office’s Mitigation Plan Approval Process and the CPUC’s Audit Process Do Not Hold Utilities Sufficiently Accountable

Key Points

• The Energy Safety Office approved mitigation plans despite identifying deficiencies in how utilities planned to prioritize mitigation activities. Subsequent external reviews established that these planning deficiencies were followed by a lack of mitigation efforts in areas of highest risk of wildfire.
• To better hold utilities accountable for the initiatives identified in their past mitigation plans, the Energy Safety Office needs to require utilities to systematically address the findings of external reviews in their plans.
• The CPUC conducts audits to determine whether utilities are in compliance with rules designed to ensure that they are operating safely, but those audits could be improved to better ensure utilities’ compliance and consequently help mitigate the risk of utility‑caused wildfires. Specifically, the CPUC does not consistently audit all areas in the utilities’ service territories, did not audit several areas that were designated as being in high fire‑threat areas, and does not use its authority to penalize utilities when its audits uncover violations.

The Energy Safety Office Has Failed to Ensure That Utilities Focus Mitigation Activities in the Areas of Highest Fire Risk

The Energy Safety Office has approved some utilities’ mitigation plans even though the utilities’ failed to demonstrate that they are appropriately prioritizing their mitigation activities. As we discuss earlier, utilities’ reports submitted to the office indicated that their hardening initiatives have addressed a relatively small number of the miles of bare power lines in high fire‑threat areas. However, we found that the office approved mitigation plans that did not provide adequate information on how utilities prioritized those initiatives. State law requires utilities to submit mitigation plans to the office for review and approval. According to the Energy Safety Office’s director, the office’s approach to reviewing mitigation plans is focused on evaluating the utilities’ processes for considering risks, such as ignition risk from equipment failure or vegetation contact, when making their decisions. ⁸ According to the 2021 mitigation plan guidelines template, a risk‑informed decision‑making process incorporates an assessment of the overall ignition probability, estimated wildfire consequence for specific electric lines and equipment, and estimation of wildfire and power shutoffs’ risk‑reduction impact, among other factors. Despite this focus, the office approved utilities’ 2020 and 2021 mitigation plans even though the utilities had not provided sufficient information on how they used risk modeling outcomes to inform decision‑making processes, circuit prioritization for mitigation efforts, and mitigation selection. Moreover, the Energy Safety Office acknowledged the absence of this information in its summary of changes for the 2022 mitigation plan update guidelines. As described below, external reviews and the office’s own audits confirmed the significance of this deficiency, as these reviews and audits established that PG&E did not focus its mitigation activities on the highest risk areas.

For example, the Energy Safety Office conditionally approved PG&E’s 2020 mitigation plan in June 2020 even though it found that PG&E did not describe in sufficient detail where vegetation management was most necessary or how it prioritized deployment of vegetation management initiatives in its plan. In subsequent months, this weakness in PG&E’s vegetation management efforts was confirmed and highlighted by external reviews and audits. As discussed previously, the Federal Monitor noted in October 2020 that PG&E had completed the majority of its 2019 enhanced vegetation work in relatively low‑risk portions of its high fire‑threat areas and had not conducted any of its planned enhanced inspections of transmission structures in its highest threat areas. Moreover, the Energy Safety Office published an audit in February 2021, which found that during 2020, PG&E continued to conduct enhanced vegetation management primarily in areas of lower fire risk. The audit concluded that PG&E’s 2020 vegetation management program appears not to have sufficiently prioritized or reduced the risk of wildfires.

In its review of PG&E’s 2021 mitigation plan, the Energy Safety Office determined that PG&E made progress in updating its vegetation risk model in a way that PG&E claimed would allow it to prioritize work in greater detail. However, the office’s review found that the utility failed to demonstrate that it was properly prioritizing other mitigation activities, particularly power line replacement and system hardening efforts. Despite these and other concerns, the office approved PG&E’s 2021 mitigation plan in September 2021. Once again, a subsequent external review confirmed the extent of the problem with PG&E’s inadequate prioritization of mitigation activities. In its 2021 mitigation plan, PG&E committed to conducting 180 miles of system hardening in 2021, 80 percent (or 144 miles) of which would be in high wildfire risk areas, in fire rebuild areas, or in power shutoff mitigation areas. The Federal Monitor published a report in November 2021 indicating that up to that point PG&E had hardened 168 total miles but only 36.5 (22 percent) of these miles were in high wildfire risk areas. The Energy Safety Office identified similar problems with other utilities’ mitigation plans that it approved. For example, it approved SDG&E’s 2021 mitigation plan despite noting that the utility did not provide sufficient detail on how it prioritized high fire‑threat areas for mitigation activities, such as moving power lines underground and installing covered power lines.

In its guidelines for utilities’ preparation of their 2022 mitigation plans, the Energy Safety Office attempted to address the problems described above by requiring utilities to detail how their risk models will be used to inform how they prioritize mitigation activities. However, the office’s internal procedures for reviewing mitigation plans still contain a fundamental flaw that needs to be addressed. These procedures indicate that certain deficiencies in a utility’s mitigation plan should not prevent the office’s approval of a mitigation plan and that the office may allow the utility to address these deficiencies in a subsequent mitigation plan. In contrast, other deficiencies—known as critical issues—are major concerns and must be addressed before the office can consider the plan for approval. The procedures provide examples of both critical issues and deficiencies. However, an example in the procedures that states, “Utility provides little discussion in how it uses the results of its risk scoring to determine grid hardening,” is classified as a deficiency that can be addressed in a subsequent year’s mitigation plan. This procedure and accompanying example as stated enable the Energy Safety Office to continue to approve mitigation plans that do not clearly define where mitigation activities will occur. By not characterizing this example as a critical issue, the office does not hold utilities accountable for conducting these activities in areas of highest risk for wildfire.

Current Mitigation Plans Do Not Incorporate the Results of External Reviews

The Energy Safety Office has not required that utilities address in their mitigation plans the issues identified by oversight mechanisms—such as audits and external reviews of their mitigation activities—resulting in plans that are not responsive to previously identified deficiencies. As discussed earlier, the Federal Monitor reported deficiencies with PG&E’s vegetation work and also reported that as of August 2020, PG&E had failed to conduct any of the enhanced inspections of approximately 1,000 transmission structures in high fire‑threat areas as planned for in its 2020 inspections. We reviewed PG&E’s 2021 mitigation plan submitted in February 2021 and found that the utility referenced how it would address the Federal Monitor’s finding on its vegetation management program, but it did not address the Federal Monitor’s finding relating to its lack of enhanced inspections. Although PG&E’s 2021 mitigation plan indicated that it intended to complete enhanced inspections of transmission structures, the Federal Monitor reported in November 2021 that PG&E had not in any previous year met the inspection commitments in its mitigation plans. Requiring PG&E and other utilities to specifically address these types of findings from external reviews would help the Energy Safety Office better hold utilities accountable for achieving year‑over‑year progress. 

The Energy Safety Office’s director expressed concern that there is no definitive source for all the oversight mechanisms to which the utilities are subject. She also stated that she believed tracking and including issues identified by oversight mechanisms in their mitigation plans must be the responsibility of the utilities. However, if utilities are to bear the responsibility for tracking the issues identified by external reviews, the office needs to update its mitigation plan guidelines to establish that requirement. By doing so, the office can define the types of oversight entities, mechanisms, and issues that need to be included in the mitigation plan and also take steps to verify the information utilities include.

The CPUC’s Audits Could Be Improved to Ensure That Utilities Are Performing Critical Wildfire Mitigation Efforts in High Fire‑Threat Areas 

The CPUC’s audits play an important role in ensuring that utilities safely operate the electrical grid, but they could be improved to better ensure utilities’ compliance and help mitigate the risk of utility‑caused wildfires. The CPUC’s mission is to, among other things, assure that utility services are safe. According to the program manager for the CPUC’s Electric Safety and Reliability Branch (safety and reliability program manager), in addition to conducting incident investigations and reviewing reports the utilities provide, the CPUC uses audits to determine whether utilities are in compliance with the rules designed to ensure that they are safely operating the electrical grid. ⁹ We reviewed the CPUC’s distribution and transmission power line audits, which address overhead and underground electrical systems. These audits determine whether utilities are following the construction, maintenance, and inspection requirements outlined in various General Orders. For example, some of these General Orders require utilities to replace electrical equipment that may be at risk of failing, to perform inspections of their electrical equipment, and to conduct vegetation management around power lines. However, there are problems with key aspects of the CPUC’s audit process.

The CPUC does not consistently audit all utility districts, and for those audits it does perform, it cannot demonstrate that it prioritizes districts that are in areas of increased fire risk. ¹⁰ Utility districts are geographic service areas designated by utilities.                 Although the safety and reliability program manager indicated that the CPUC’s audit manual calls for it to audit each utility’s districts within a five‑year cycle, we found that the CPUC did not audit each power line distribution district (distribution district) within the most recent five‑year period, as we show in Figure 12. Specifically, we noted that during the five‑year cycle of 2016 through 2020, the CPUC audited fewer than 70 percent of the utilities’ distribution districts. The safety and reliability program manager indicated that the CPUC was unable to complete all of those audits because the branch had other duties, including investigating utility‑related wildfires, which necessitated significant efforts and limited its ability to perform additional audits. However, the safety and reliability program manager also acknowledged that since 2019, the branch has had a diminished role in investigating these fires.

The CPUC did not audit several districts that contain areas of elevated or extreme fire risk. Notably during the five‑year period from 2016 through 2020, the CPUC failed to conduct audits of distribution power lines in counties that contain areas of elevated and extreme fire risk, including portions of Butte, Tehama, and Shasta counties—where major fires have occurred in the past. Although the safety and reliability program manager stated that the CPUC used risk factors identified in the audit manual, including past audit performance, accident data, or indications of safety or reliability problems, she was unable to provide any documentation showing how the risk factors were applied when selecting which districts to audit. As a result, the CPUC could not demonstrate how it weighs the risk of utility‑caused wildfires when prioritizing the audits it performs.

Figure 12

It Has Been More Than Five Years Since the CPUC Audited Certain Utility Districts

We also found that the CPUC does not use its authority to penalize utilities when its audits uncover violations. In 2014 the CPUC adopted an electric safety citation program that gave staff the authority to issue penalties for certain violations of law and of General Orders, including those identified through audits. However, as of November 2021, the CPUC had not issued any penalties resulting from violations that its safety and enforcement division found during audits. The safety and reliability program manager informed us that it is the CPUC’s practice to issue penalties for significant issues, which may be found through incident investigations where individuals were hurt or killed, or where buildings were destroyed, but that these types of immediate safety hazards are rarely found during audits.

In our review of CPUC audits, we identified several instances where the CPUC identified violations of General Orders that were the same as those for which it issued penalties in incident investigations. For example, the CPUC issued a $2.5 million penalty to a utility in 2021 for nearly 55,000 violations of a General Order requiring inspections of distribution poles, and we found that the CPUC had identified similar issues in at least two of its distribution district audits. The CPUC identified more than 200 violations of the same General Order in one 2020 distribution district audit, and about 2,400 similar violations in a second 2020 distribution district audit. Additionally, we found that in 2017 the CPUC issued a $50,000 penalty to a utility for a single violation of a General Order requiring vegetation management. Although we identified three audits that the CPUC performed in 2019 and 2020 that identified similar violations, it did not issue any penalties for those violations.

We asked the CPUC for perspective on why it did not issue penalties for audit findings. The safety and reliability program manager indicated that penalties may be viewed as a punitive method for gaining compliance, but they do not necessarily ensure an increase in the utility’s compliance. However, the CPUC issues penalties for violations of General Orders it uncovers during incident investigations, and if it believes that those penalties are merited, it is not clear why similar violations discovered during audits should not be similarly penalized. Because the CPUC’s mission includes assuring that utility services are safe, its focus should be on preventing deficiencies that could result in negative outcomes, rather than only imposing penalties after an incident such as a fire, injury, or death. Although penalties associated with audit findings may not result in the same dollar amounts as those applied after an investigation, issuing penalties based on audit findings would elevate the importance of the safety practices that CPUC audits review.

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Other Areas We Reviewed

Recent Audits of Utilities’ Mitigation Expenditures

Recent audits of utility expenditures questioned whether the CPUC should allow the three largest utilities to recover through their rates approximately $2.5 billion, collectively, as wildfire mitigation costs. According to the CPUC, ratemaking is done on a prospective basis, and its practice is not to authorize increased rates to account for previously incurred costs. The general rate case dictates the electrical rates that the utilities can charge customers for the cost of owning, operating, and maintaining their facilities, and they include the cost of utilities’ efforts to mitigate the risk of causing wildfires. However, state law requires utilities to track in a specific account (mitigation account) actual expenditures for fire risk mitigation that are not otherwise covered by rates approved in their general rate case. State law also allows utilities the alternative to recover those costs through an application for cost recovery at the end of the period covered by the mitigation plan. Under either scenario, the utility must certify that it did not receive authorization for the costs from a previous proceeding.

In June 2020—with the Wildfire Safety Division, the predecessor to the Energy Safety Office, acting as a project manager—CPUC hired a contractor to assess whether costs in the six utilities’ 2019 and 2020 mitigation plans duplicated expenditures approved in previous general rate cases. The audit reports for PG&E, SCE, and SDG&E determined that nearly $2.5 billion in costs were already paid for through the utilities’ previously approved rates, or that additional justification and documentation from the utilities was necessary to make a determination of whether the costs were already paid for through the utilities’ previously approved rates. The utilities disagreed with many of the audit results and in several instances stated either that they did not intend to claim reimbursement for the costs in question or that they disagreed with the contract auditor about whether the costs were part of the activities described in their general rate case. Nevertheless, the contract auditor generally stood by its findings and in multiple instances stated that utilities should provide additional information or that the CPUC should carefully monitor future claims by the utilities to ensure that these costs are not passed on to customers again in the form of higher rates.

The CPUC’s Energy Division program manager stated that there are several safeguards in place to prevent utilities from double‑charging customers for the same expenditures. Specifically, she discussed how the CPUC’s proceedings for setting rates may include requiring utilities to provide proof that expenditures are different from those authorized in the past. She also cited the involvement of others, such as outside stakeholder groups, filing protests during those proceedings and in some cases the individual overseeing the proceeding, the utility itself, or an advocates office ordering or conducting an audit. However, the recently conducted audits highlight potential weaknesses in the rate‑setting process, and until the CPUC addresses these findings, questions remain about the appropriateness of the rates utilities are authorized to charge.

Recommendations

To ensure that it does not authorize cost recovery, and the resulting rate increases, for activities that were part of a utility’s previous general rate case, the CPUC should perform audits of the utilities’ wildfire mitigation costs before approving recovery of those costs. In addition, the CPUC should implement sufficient safeguards to ensure the appropriateness of the costs passed on to customers.

To ensure that utilities do not over‑recover, or charge ratepayers more than they should for the activities they perform, the CPUC should make certain that if utilities request reimbursement for the costs questioned in the contractor audits, the utilities provide sufficient quantifiable and detailed analyses to substantiate that the costs were not paid for through the utilities’ previously approved rates.

CPUC Safety Culture Assessments

The CPUC has not required safety culture assessments of utilities, which are reviews that emphasize appropriately prioritizing employee safety and that are responsive to risk factors, such as wildfires—pursuant to the state law that requires such assessments. An amendment to state law that took effect in January 2019 established that the Commission must require a safety culture assessment of each of the utilities by an independent third‑party evaluator at least once every five years. Because catastrophic safety failures often result from multiple failures, rather than the action or inaction of a single individual, a safety culture supports the process of identifying hazards and implementing adequate safeguards throughout the organization. Essentially, a safety culture is a set of organizational principles, beliefs, and norms in which safety is a predominant objective and is continuously reinforced. Safety culture assessment practices in other industries often include document reviews and interviews with and surveys of staff throughout the organization. However, the CPUC did not initiate a rulemaking for performing safety culture assessments until October 2021.

The Commission delayed initiating its safety culture assessment rulemaking for more than two years after the state law took effect. The amendment to state law requiring these assessments also established the requirement for utilities to annually prepare and submit a mitigation plan, among other things. According to the director for the CPUC’s Safety Policy Division (safety policy director), in implementing the new state law, the CPUC focused on developing the process for mitigation plans and developing and implementing policy related to wildfire cost recovery. He explained that the CPUC anticipates that it will be ready to begin conducting culture assessments in 2023. When we asked why the CPUC did not prioritize the safety culture requirement, the safety policy director indicated that the five‑year period for safety culture assessments seemed less time sensitive than other requirements, such as developing a process for annual mitigation plans. According to the program manager for the Safety Policy Division, the CPUC views the PG&E safety culture assessment resulting from the San Bruno explosion as the first assessment conducted under this new state law. However, this assessment was initiated in April 2016, more than two years before the law requiring safety culture assessments took effect. Further, the CPUC had not yet initiated a rulemaking for conducting these safety culture assessments when the PG&E assessment began. Nonetheless, until the CPUC begins requiring culture assessments as state law requires, it lacks assurance of the extent to which utilities’ cultures are prioritizing safety.

The Energy Safety Office’s Compliance Program

In September 2021, the Energy Safety Office established emergency regulations for the process it uses to ensure that utilities comply with mitigation plans and requirements related to mitigating the risk of wildfires. State law authorizes the office to issue a notice of defect or notice of violation, which we refer to collectively as compliance notices, to direct utilities to correct any noncompliance with approved mitigation plans, laws, regulations, or guidelines, and it authorizes the office to perform compliance investigations. According to emergency regulations that took effect in September 2021, a notice of defect identifies a deficiency, error, or condition that requires correction because it increases the risk of ignition posed by electrical lines and equipment. A notice of violation identifies noncompliance with an approved mitigation plan, law, regulation, or guideline within the Energy Safety Office’s authority, such as failing to perform inspections described in a mitigation plan.

The Energy Safety Office’s emergency regulations allow it to issue compliance notices on a temporary basis, but it is in the process of creating permanent regulations. The emergency regulations will expire in June 2022; however, the Energy Safety Office’s general counsel stated that the office has engaged a contractor to help manage the implementation of permanent regulations.

We conducted this performance audit in accordance with generally accepted government auditing standards and under the authority vested in the California State Auditor by Government Code section 8543 et seq. Those standards require that we plan and perform the audit to obtain sufficient, appropriate evidence to provide a reasonable basis for our findings and conclusions based on the audit objectives. We believe that the evidence obtained provides a reasonable basis for our findings and conclusions based on our audit objectives.

Respectfully submitted,

MICHAEL S. TILDEN, CPA
Acting California State Auditor

March 24, 2022

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Appendix A

Scope and Methodology

The Joint Legislative Audit Committee (Audit Committee) directed the California State Auditor to conduct an audit of the role of the CPUC in ensuring a safe and reliable electrical system in California. Because the Legislature transferred all of the functions of the CPUC’s Wildfire Safety Division to the Office of Energy Infrastructure Safety during the course of our audit, we included the office in our review. Specifically, we reviewed the CPUC’s audit process to determine whether it consistently assessed utilities’ compliance with General Orders, determined whether the three largest utilities submitted required elements for their 2020 safety certifications, and assessed the CPUC’s efforts to oversee utilities’ power shutoffs. We also reviewed the Energy Safety Office’s review and approval of mitigation plans and safety certifications. Table A lists the objectives that the Audit Committee approved and the methods we used to address them.

Table A

Audit Objectives and the Methods Used to Address Them

AUDIT OBJECTIVE		METHOD
1	Review and evaluate the laws, rules, and regulations significant to the audit objectives.	Reviewed relevant laws and regulations related to electrical grid safety as well as the CPUC’s General Orders.
2	Review the CPUC’s mission and determine whether the CPUC is performing all of its required functions related to overseeing the safety of the electrical system.	Selected and reviewed the approved 2020 safety certifications of the three largest utilities, each with more than 250,000 customers. Determined whether the utilities submitted all required elements for their 2020 safety certifications. Reviewed the CPUC records of completed audits to determine whether the CPUC performed audits from 2016 through 2020 in a timely manner. Evaluated the CPUC’s process for complying with the requirement in state law that utilities submit safety culture assessments. Reviewed the CPUC’s process for evaluating the sufficiency of RAMPs. We found that although the CPUC’s development of this process is ongoing, it has implemented requirements for utilities to demonstrate that they are prioritizing safety in their risk framework. The CPUC is currently undertaking a rulemaking proceeding to improve this process. Determined whether the Energy Safety Office issued any corrective actions before approving the utilities’ 2021 mitigation plans.
3	For the past five years, evaluate the steps that the CPUC has taken to oversee the safety of utilities’ electric systems by determining the following: a. The staffing and budget resources the CPUC has allocated to this purpose. b. Whether the CPUC has assessed needed infrastructure improvements. c. Whether the CPUC has developed all reasonable wildfire mitigation protocols. d. Whether the CPUC has identified and procured needed wildfire mitigation equipment.	Obtained and reviewed budgeted and actual expenditures for the CPUC for the past five fiscal years. Reviewed budget change proposals submitted by the CPUC and the Energy Safety Office over the past five years, from fiscal years 2016–17 through 2020–21. We concluded that the CPUC requested additional staff positions from fiscal years 2017–18 through 2020–21, some of which were positions for the establishment of the Energy Safety Office. Analyzed the Energy Safety Office’s data to determine the total mileage of utility power lines in the State and the total mileage of utility power lines in high fire‑threat areas. We found that the six investor‑owned utilities reported to the Energy Safety Office that they have nearly 277,000 miles of power lines in the State, and of those, more than 74,000 miles are in high fire‑threat areas. Determined the total miles of power lines that have undergone improvement to mitigate the risk of wildfire in fiscal year 2020–21—such as covering conductors, burying lines, and vegetation removal using available CPUC and Energy Safety Office GIS data. Obtained data from the CPUC for the past five years to determine the number and location of fires the three largest utilities reported causing. Obtained power line data from the CPUC and the Energy Safety Office but determined that both entities lacked the historical data necessary for us to determine how many miles of power lines in high fire‑threat areas the utilities have improved to mitigate the risk of wildfire for the last five years. Obtained data from the CPUC for the past five years to determine the number and location of fires caused by the three largest utilities. Reviewed standards for equipment in other localities and countries and found few requirements for installing covered power lines or otherwise hardening electrical grids. We found that Victoria, a state in Australia, requires that all new or replaced electrical lines be either covered or underground. We discussed utilities’ needs to make improvements to the electrical grid in our report. Obtained CPUC’s perspective on setting design standards for power line hardening in high fire‑threat areas. CPUC expressed concerns that establishing design standards for equipment in high fire‑threat areas would limit flexibility and innovation and would not be a good alternative to its risk‑based decision‑making oversight.
4	For the past five years, review the CPUC’s efforts to fulfill its mission through its oversight of utilities’ power shutoffs by determining the following: a. Whether the CPUC’s oversight decisions have been objectively reasonable and consistent with its mission, state laws, and CPUC rules and regulations. b. Whether the CPUC’s efforts have been appropriately targeted and whether the outcomes of these efforts are being appropriately tracked, measured, and evaluated. c. The extent to which the CPUC is reporting accurate and reliable information and data on power shutoffs.	Reviewed factors the CPUC may evaluate after a power shutoff to determine reasonableness. Reviewed the CPUC’s process for evaluating post‑event reports to determine if the process is sufficient and appropriate. Selected five power shutoff post‑event reports and determined whether the CPUC’s assessment addressed key elements. Determined whether CPUC’s power shutoff draft compendium includes key elements from the relevant CPUC General Orders. Reviewed the CPUC’s efforts to track, measure, and evaluate utilities’ corrective actions in response to post‑event report findings for the five reports we selected. We determined that it does not currently follow up on these issues. Reviewed 15 post‑event reports from 2020 and 2021 and determined if there was damage to the utility’s infrastructure during the shutoff that could have created a wildfire ignition had the shutoff not occurred.
5	Evaluate the processes the CPUC has established for reviewing and approving utilities’ plans for power shutoffs or, in the case of PG&E, its biweekly reports. Include an identification and evaluation of the criteria the CPUC uses to review and approve the plans and reports.	Determined whether the CPUC or the Energy Safety Office assesses whether the thresholds utilities use for triggering a power shutoff are sufficient and appropriate and concluded that they do not perform such assessments. Identified the criteria for PG&E’s biweekly reports established in a Commission ruling. We reviewed two biweekly reports and found that they contained the required elements. We also determined that the CPUC released PG&E from the requirement to submit biweekly reports in November 2021.
6	Evaluate whether any identified concerns should be addressed through changes in state law or the CPUC’s practices.	Interviewed key staff and reviewed relevant materials to determine if the Energy Safety Office requires utilities to address issues identified by oversight mechanisms in their mitigation plans.
7	Review and assess any other issues that are significant to the audit.	Reviewed relevant program information and determined that the microgrid incentive program is currently designed to incentivize placement of microgrids in areas that are at most risk for power shutoffs and that will be most adversely affected by power outages. The anticipated program launch date is 2022. Assessed the criteria for the CPUC’s solar incentive program and concluded that it provides financial incentives to increase grid resiliency for communities in high fire‑threat districts. Assessed the criteria for the CPUC’s net energy metering (NEM) program and interviewed staff. The CPUC has not, to date, adopted a decision relating to NEM that prioritizes high fire-threat districts.

Source: Audit workpapers.

Assessment of Data Reliability

The U.S. Government Accountability Office, whose standards we are statutorily obligated to follow, requires us to assess the sufficiency and appropriateness of the computer-processed information we use to support our findings, conclusions,
and recommendations.

In performing this audit, we relied on extracts from the CPUC’s accounting system to determine its total expenditures for regulatory purposes and its expenditures related to regulating electric utilities for fiscal years 2016–17 through 2020–21. The data came from the California State Accounting and Reporting System (CALSTARS) and the Financial Information System for California (FI$Cal). However, a report our office issued in February 2022 identified findings in FI$Cal’s overall information technology general controls environment. ¹¹ State of California: Internal Control and Compliance Audit Report for the Fiscal Year Ended June 20, 2020, Report 2020‑001.1. These deficiencies resulted in pervasive risks that impact the ability to rely on FI$Cal data used for financial reporting. Because of the multiple systems involved and our inability to rely on information reported in FI$Cal, it was not cost-effective to conduct a data reliability assessment.

We obtained cost data for large wildfires and other significant events from 2015 through 2021 from the National Interagency Fire Center to identify fire suppression costs. Because we use these data solely for background or context, we determined that a data reliability assessment was not necessary.

We obtained data from the CPUC identifying the microgrid projects funded through the EPIC program from 2015 through 2020 to determine the number of microgrids it funded. Because we used these data solely for background or context, we determined that a data reliability assessment was not required.

We obtained a list of utility distribution districts from the CPUC to determine whether it had performed audits of each district. To evaluate the data, we performed dataset verification and identified no issues. We verified the accuracy and completeness of the data by comparing the CPUC’s utility distribution district list to the utilities’ district maps and found that the list did not include three utility districts. We obtained corrected information that aligned with the district maps and used this list for our analysis. Although we found the CPUC’s list of utility district data to be not sufficiently reliable for the purposes of determining the full list of utility distribution districts, the corrected information provided sufficient evidence in total to support our findings, conclusions, and recommendations.

We obtained ignition data reported by PG&E, SCE, and SDG&E to the CPUC from 2015 through 2020 to determine the causes of utility-caused ignitions. To evaluate these data, we performed dataset verification procedures and electronic testing of key data elements and did not identify any issues. We were unable to perform accuracy and completeness testing for these data because the three utilities provided the ignition data to the CPUC; thus the data cannot be corroborated. As a result, we concluded that they are of undetermined reliability. Although this determination may affect the precision of the numbers we present, there is sufficient evidence in total to support our findings, conclusions, and recommendations.

We obtained data on outages caused by PG&E’s power-line settings program from July 2021 through November 2021 from the CPUC. We used these data to determine the number of unplanned outages, the average outage time per customer, and the number of customers impacted as a result of these outages. To evaluate these data, we performed dataset verification procedures and electronic testing of key data elements and did not identify any issues. We were unable to perform accuracy and completeness testing for these data because it is the only source of unplanned outage data available and therefore could not be compared against another source. As a result, we concluded that the data are of undetermined reliability. Although this determination may affect the precision of the numbers we present, there is sufficient evidence in total to support our findings, conclusions, and recommendations.

We obtained CPUC data on power shutoff events since 2013 to determine whether the CPUC is reporting accurate and complete information on the power shutoff events and to calculate summary information regarding those events. We performed accuracy testing on a random sample of five power shutoff events by tracking key data elements to their supporting post-event reports, and we found more than one error each in the power shutoff event end dates and the total customers impacted. We also traced all post-event reports available on the CPUC website to the CPUC data to ensure that all power shutoff events from 2017 through 2021 were accounted for in the data. We found that data for five power shutoff events were missing, and we compiled summary information for those missing events. We concluded that the detailed data were not sufficiently reliable for our purposes. Although this determination may affect the precision of the numbers we present, there is sufficient evidence in total to support our findings, conclusions, and recommendations.

We relied on electronic data obtained from the Energy Safety Office that contain geographical data it obtained from the six utilities for the period July 2020 through June 2021. We performed electronic testing of the data and interviewed staff knowledgeable about the data. We found the Energy Safety Office’s data to be of undetermined reliability for our purpose of determining the status of power lines throughout the State and assessing the utilities’ mitigation efforts. Although this determination may affect the precision of the numbers we present, there is sufficient evidence in total to support our findings, conclusions, and recommendations.

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Appendix B

Summary of Public Safety Power Shutoffs

Table B reflects the total number of power shutoff events the utilities implemented from 2013 through 2021. The table includes the minimum and maximum length of each power shutoff and the total number of customers affected per event.

Table B

Summary of Public Safety Power Shutoff (PSPS) Events

Utility	PSPS YEAR	PSPS Start Date	PSPS End Date	Minimum and Maximum Length of Power Shutoff (hours)	Total Customers Impacted
SDG&E	2013	5-Oct	6-Oct	5.52–8.88	183
SDG&E	2014	14-Jan	15-Jan	19.52–32.1	85
SDG&E		14-May	15-May	7.43–32.3	1,192
SDG&E		24-Nov	25-Nov	9.45–12.62	90
SDG&E	2017	21‑Sep	22‑Sep	18.33–18.33	3
SDG&E		20‑Oct	21‑Oct	37.97–37.97	3
SDG&E		23‑Oct	25‑Oct	6.1–50.82	175
SDG&E		5‑Dec	11‑Dec	21.07–144.87	2,164
SDG&E		14‑Dec	15‑Dec	9.12–17.28	658
PG&E	2018	14‑Oct	17‑Oct	12.6–60.38	60,086
SDG&E		15‑Oct	16‑Oct	7.08–27.7	379
SDG&E		19‑Oct	20‑Oct	30.53–30.53	19
SDG&E		11‑Nov	16‑Nov	5.48–93.68	24,081
PG&E	2019	8‑Jun	9‑Jun	11.77–20.63	22,327
SCE		16‑Sep	19‑Sep	*	14,500
PG&E		23‑Sep	26‑Sep	0.4–32.12	69,627
SCE		24‑Sep	24‑Sep	5.8–5.8	85
PG&E		5‑Oct	6‑Oct	12–17.7	11,304
PG&E		8‑Oct	12‑Oct	5.37–89.13	728,980
SCE		9‑Oct	12‑Oct	0.02–62.77	24,113
SDG&E		10‑Oct	11‑Oct	18.53–23.72	395
SCE		16‑Oct	21‑Oct	3.78–25.37	440
PG&E		23‑Oct	25‑Oct	5.13–51.55	176,620
SCE		23‑Oct	28‑Oct	2.32–106.18	30,958
SDG&E		24‑Oct	1‑Nov	0.13–58.25	47,616
SCE		27‑Oct	3‑Nov	4.87–110.33	126,364
PG&E		26‑Oct	4‑Nov	0.02–162.77	941,269
SCE		17‑Nov	17‑Nov	4.7	49
SDG&E		17‑Nov	18‑Nov	*	21
PG&E		20‑Nov	21‑Nov	7.43–38.68	49,086
SCE		25‑Nov	27‑Nov	5.67–42.8	1,192
SCE	2020	2‑Aug	4‑Aug	44.27	17
PG&E		7‑Sep	13‑Sep	0.03–133.83	168,599
SDG&E		8‑Sep	9‑Sep	3.4–13.5	49
SCE		9‑Sep	11‑Sep	8.92–54.78	252
PacifiCorp		13‑Sep	14‑Sep	7.6–32.9	2,559
PG&E		26‑Sep	29‑Sep	14.65–60.48	64,295
PG&E		13‑Oct	17‑Oct	0.02–62.95	40,574
SCE		16‑Oct	16‑Oct	4.5–9.75	86
PG&E		21‑Oct	23‑Oct	7.2–47.48	30,154
PG&E		25‑Oct	28‑Oct	1.45–78.92	345,470
SCE		26‑Oct	28‑Oct	7.08–57.02	36,257
SDG&E		26‑Oct	27‑Oct	5.47–8.12	4,373
SCE		6‑Nov	7‑Nov	3.2–20.65	1,327
SCE		16‑Nov	18‑Nov	2.67–38.17	506
SCE		26‑Nov	28‑Nov	0.27–53.43	20,619
SCE		2‑Dec	4‑Dec	0.32–56.15	63,494
SDG&E		2‑Dec	9‑Dec	12.1–61.68	89,505
PG&E		2‑Dec	3‑Dec	0.76–22.07	617
SCE		7‑Dec	11‑Dec	0.27–53.75	78,997
SCE		18‑Dec	24‑Dec	0.18–31.48	27,513
SDG&E		23‑Dec	24‑Dec	7.58–23	6,797
SCE	2021	14‑Jan	21‑Jan	3.52–175.83	116,234
PG&E		18‑Jan	26‑Jan	10.7–184.02	5,099
SCE		13‑Apr	13‑Apr	2.87	78
PG&E		17‑Aug	20‑Aug	15.98–62.65	48,155
PacifiCorp		17‑Aug	18‑Aug	4.77–9.2	1,953
PG&E		20‑Sep	21‑Sep	7.72–18.58	2,968
SCE		30‑Sep	30‑Sep	9.82	9
PG&E		11‑Oct	14‑Oct	11.98–79.35	23,504
SCE		11‑Oct	12‑Oct	20.17–21.05	40
SCE		15‑Oct	16‑Oct	5.2–26.27	67
PG&E		15‑Oct	16‑Oct	13.17–39.42	666
SCE		22‑Oct	22‑Oct	7.05	112
SCE		24‑Nov	26‑Nov	*	78,514
SCE		21‑Nov	22‑Nov	*	5,235
SDG&E		24‑Nov	26‑Nov	*	5,858