California’s largest utility has escaped from bankruptcy after 18 months. Its next challenges are the same ones that put it there in the first place.
Jeff St. John • July 02, 2020
Pacific Gas & Electric has officially ended its 18-month bankruptcy. Now it must undertake a years-long effort to prevent a repeat of the disasters that pushed it into insolvency in the first place.
On Wednesday, PG&E announced its successful exit from Chapter 11 bankruptcy protection, after U.S. Bankruptcy Judge Dennis Montali approved its $59 billion restructuring plan. The plan included tens of billions of dollars in settlement payments to victims of the 2017 and 2018 wildfires caused by failures of its power grid, including the Nov. 2018 Camp fire, for which it pleaded guilty to 84 felony counts of involuntary manslaughter last month.
But PG&E faces a long and difficult road ahead. The San Francisco-based utility is emerging with a massive debt load that could make it harder to raise the tens of billions of dollars of investment needed to prevent its power grid from causing more devastating wildfires. It’s struggling to find cost-effective ways to protect millions of customers from fire-prevention blackouts that may need to continue for years.
PG&E must keep up with the state’s ambitious clean energy, environmental and electrification goals. And all of this must happen without excessively raising customer rates if it’s to avoid political and customer backlash.
Many more long-term challenges await PG&E, such as adapting to large portions of its customer base being served by community-choice aggregators, or its natural gas network being rendered obsolete by the state’s mandated target of zero carbon by 2045. But first, PG&E must deliver on every utility’s core responsibilities, said Isaac Maze-Rothstein, grid edge analyst at Wood Mackenzie Power & Renewables — “the pillars of safe, affordable and reliable” service.
“They need to not cause any more fires,” Maze-Rothstein said, adding, “They need an alternative to almost all PSPS events” (which stands for “public-safety power shutoffs”) to avoid subjecting millions of residents to multiday blackouts in the name of fire prevention.
Somehow, PG&E must achieve both tasks without raising rates so much that customers “explore alternatives.” After all, if PG&E keeps raising rates for electricity that can’t be relied on during emergencies, customers may demand options to defect from its service — a version of the “utility death spiral” threat purportedly posed by rooftop solar and behind-the-meter batteries that has yet to emerge in the real world.
“For the next three years, if they can do those things, they can continue to stay in business,” Maze-Rothstein said. “Everything else is an afterthought.”
Here’s a look at PG&E’s four major challenges, both in the short and longer term.
1. Safety: Reducing wildfire risk to as close to zero as possible
PG&E’s first priority is preventing more devastating wildfires, since another one could drive it back into bankruptcy, said Dan Richard. The former PG&E senior executive is an adviser to 58 cities and 10 counties that were promoting a plan to convert PG&E into a customer-owned utility — an option that remains a possibility if the utility can’t meet the safety standards put in place by state regulators.
Gaining bankruptcy court approval means PG&E will be able to access a $21 billion state fund to shield it and California’s other investor-owned utilities from massive fire liabilities. But another blaze on the scale of the Nov. 2019 Paradise fire, which led to an estimated $30 billion in liabilities, could deplete the fund and undermine the willingness of state leaders to offer more aid, Richard said.
PG&E plans to invest about $40 billion over the next five years into its power grid. Of that, about $7.8 billion over the next three years is tied to its wildfire-mitigation efforts, including enhanced vegetation clearing along 1,800 miles of distribution lines, covering or burying another 240 miles of lines, installing hundreds of cameras and weather stations, and deploying nearly 600 grid-sectionalizing devices to reduce the scope of fire-prevention outages.
PG&E was already struggling with this massive undertaking before the COVID-19 pandemic added to its workforce challenges. U.S. District Court Judge William Alsup, who oversees PG&E’s criminal probation for its 2010 San Bruno natural-gas pipeline explosion, has contended that the utility has failed to correct obvious fire risks over the past year.
Moving too slowly on its mandated wildfire-prevention goals could open up PG&E to sanction or even state receivership under the terms of its agreement with the California Public Utilities Commission. A law that would give the state authority to take over PG&E was passed by lawmakers this week and is awaiting Gov. Gavin Newsom’s signature.
Beyond proving how many miles of grid it has cleared of overhanging tree limbs and how many transmission towers it’s inspected, PG&E should be taking steps to better understand the risks its power grid is subjected to across a mountainous and forested territory facing increasingly dry and windy weather due to climate change. That’s the view of Michael Wara, head of Stanford University’s Climate and Energy Policy Program and a member of the governor’s Wildfires Blue Ribbon Commission.
For example, while current regulations call for clearing brush and branches within 10 feet of poles and wires, reports from the 2017 California Wine Country fires indicate that at least one of them was caused by a tree limb blown into wires from far outside that distance.
“They should be doing things that are much more sophisticated, like using machine learning to model every tree they’ve mapped with lidar, and then removing every tree far outside their easement that presents risk,” Wara said.
That may draw the ire of landowners and environmental groups, as happened with PG&E’s vegetation-clearing process last year, Wara acknowledged.
PG&E can’t eliminate these kinds of risks entirely — “they’d have to cut down every tree in the landscape,” he said. But the utility’s camera and weather station network could provide the data for this kind of analysis. While it may be costly, it’s also “incredibly valuable for the customers,” according to Wara.
2. Reliability: Investing in distributed energy for fire-prevention blackouts
Given the reality of a stretched workforce and bankruptcy-strained budget, it’s likely that PG&E will continue to rely on fire-prevention blackouts for the next few years.
“Nobody wants to hear that their power’s going to be shut off. It is absolutely a last resort,” Wara said, adding, “We are in a last-resort situation with respect to wildfires.”
These last-resort fire-prevention blackouts cause dangers of their own, from darkening traffic signals and streetlights and leaving supermarkets and restaurants without refrigeration, to depriving sick or elderly people of electricity for medical equipment.
This has focused state lawmakers and regulators on debating whether to make PSPS events worthy of a state emergency declaration alongside floods, fires and earthquakes, and considering options for backing up at-risk residents and communities with distributed energy. The options now at hand range from the hundreds of megawatts of mobile diesel generators PG&E plans to deploy this year as a stopgap measure, to battery systems being funded by the state’s Self-Generation Incentive Program.
There’s a major debate underway over fossil fuels versus clean energy for this purpose, as evidenced by the backlash to PG&E’s plan to install natural-gas generators at substations for PSPS backup this year; while these units are cleaner than diesel, clean-energy advocates say they still emit carbon and undercut the state’s environmental goals. Advocates for the use of natural-gas microgrids reply that solar and batteries alone can’t provide more than several hours of backup at a reasonable cost.
Microgrids that combine generators, solar, batteries and distribution grid controls are the most likely solution for large customers with critical backup needs, Maze-Rothstein said. About 110 megawatts of microgrid capacity now exists in PG&E territory, including many units that kept power flowing during last fall’s PSPS events, and another 170 megawatts are being planned.
Combining customer-owned distributed clean energy with rate-based utility investments to manage them for reliability might be one solution if they can yield valuable public benefits to justify the costs to ratepayers, he said.
The CPUC is working on a microgrid proceeding to allow these kinds of cooperative efforts, and state lawmakers are debating several bills this year to fast-track key community resiliency efforts, said Amisha Rai, West Coast managing director for Advanced Energy Economy.
“How do you harness this microgrid capability around evacuation centers?” she asked. “Can you create community hubs around schools that may already have solar capacity? Can you also think about mobile source power, like electric school buses that are being deployed across the state?”
“The key thing hanging over everyone’s head is the cost,” Rai said. “There is no silver bullet on that, and it’s an even more heightened concern given the state of the economy.”
3. Affordability: Keeping rates in check amid massive investment needs
PG&E will exit bankruptcy with nearly $39 billion in debt, nearly twice its prebankruptcy debt load. That’s likely to restrict its ability to access debt markets at favorable terms to fund capital investments and force the utility to raise rates to cover its capital needs.
On Monday, credit rating agency Moody’s issued ratings for both PG&E the utility and its parent company, PG&E Corp., that reflect the risks they face in managing their debt amid ongoing wildfire risk. While the utility’s roughly $33 billion in new and reissued debt, which is secured by its assets and its rate base, earned a Baa3 rating, indicating moderate credit risk, the parent company’s $4.75 billion in new debt earned a B1 rating, or “speculative [and] subject to high credit risk.”
“PG&E’s ratings reflect several challenges that lie ahead for the company as it exits its second bankruptcy in the last two decades,” Jeff Cassella, vice president and senior credit officer, said in Monday’s announcement. The first is limiting wildfires in the face of rising wildfire risk. And then there’s the matter of “building trust with key stakeholders including state regulators, policymakers and customers.”
PG&E is forecasting a steady increase in its rate base, from roughly $44.5 billion in 2021 to as much as $60 billion by 2024. This will “put huge upward pressure on rates, precisely at a time when the economy has gone into a tailspin” due to the COVID-19 pandemic, said Dan Richard, the former PG&E executive.
PG&E has identified “potential growth opportunities” in its rate base from additional wildfire-mitigation spending, EV charging infrastructure, grid modernization and investing in distributed microgrids. The question is whether such investments would yield results that eventually lessen customer costs.
For example, PG&E already has CPUC approval for more than $250 million in EV charging infrastructure projects, largely centered on trucks, buses and work vehicles, that have been sidelined by its bankruptcy. Moving quickly on that work could not only boost its rate base but would “actually put downward pressure on rates,” AEE’s Rai said. That’s because increased electricity sales for EV charging can feed back into reduced customer rates under California’s revenue decoupling regime.
The same dynamic can also work in reverse. A COVID-19 economic slowdown could reduce electricity sales, forcing rates up at the same time that increased capital expenditure is adding to the rate base.
The same thing could happen if customers dissatisfied with unreliable service turn to self-generated alternatives, whether from battery-backed rooftop solar under net metering regulations or from microgrids that allow large customers to largely depart PG&E service.
Although PG&E’s natural-gas substation microgrid plan is on hold, future efforts to rate-base microgrids could provide the utility with a revenue-generating option to prevent customers from leaving its service. “If PG&E can be a reliable and consistent asset during a very uncertain time, that can be a value proposition for investors,” Maze-Rothstein said.
On the microgrid front, PG&E is likely to face competition from community-choice aggregators, the local and regional entities that have been growing by leaps and bounds across California. Twelve CCAs now procure electricity for more than 2.4 million of PG&E’s 5.4 million customers and could become increasingly attractive alternatives if PG&E is forced to raise rates to cover the costs of its looming investments.
4. Meeting clean energy goals for a future in flux
The rise of CCAs has also complicated PG&E’s long-term clean energy goals. While PG&E and its fellow investor-owned utilities led California’s push into utility-scale renewable energy, CCAs are expected to be responsible for the majority of new resources required to meet the state’s clean-energy mandate of 60 percent by 2030.
CCAs are also a problem for PG&E’s finances since they replace direct “bundled” customers with “distribution-only” customers. In 2017 and 2018, PG&E saw roughly $1 billion in reduced energy sales from these shifts, primarily from residential and commercial customers choosing not to opt out of new CCAs’ service, according to Wood Mackenzie Power & Renewables analyst Fei Wang. While California’s decoupling mechanisms do shelter utilities from experiencing these energy sales declines as direct revenue reductions, and a 2018 CPUC decision shifted some of the cost-shift burden from utilities to CCAs, these long-term changes will have uncertain effects on IOUs’ business models. And WoodMac “definitely expects [PG&E] to continue to lose retail customers to CCAs,” Wang said.
CCAs reacted to PG&E’s bankruptcy with a proposal to convert it to a “wires-only” utility, responsible only for maintaining its distribution and transmission network, and leaving procurement to them. CCAs have been signing renewable and energy storage contracts at a rapid clip.
At the same time, only two CCAs have yet obtained the investment-grade credit ratings that are important for securing favorable terms for raising capital to invest in the expanded procurement role seen for them in the coming decade.
“There’s a real question of their creditworthiness,” WoodMac analyst Colin Smith said — and that was before the pandemic’s hit to the state’s economy, which has left many customers unable to pay their bills. Of course, PG&E’s heavy debt load and murky fortunes could weaken its position relative to CCAs on those same terms, Smith noted.
PG&E is still busy procuring resources to meet its systemwide needs. Last month it announced contracts for 423 megawatts, or nearly 1.7 gigawatt-hours, of energy storage systems to help meet a statewide need for resources to maintain grid stability in the absence of natural-gas power plants set to close in the coming years.
It’s also responsible for procuring zero-carbon resources to replace the 2.2-gigawatt Diablo Canyon nuclear power plant by the time it shuts down in 2025 — a big hole that will likely need to be filled by renewables backed by batteries.
“How fast and how realistically can you add storage to replace things like Diablo Canyon?” Smith said. “How fast can it be properly integrated? These are big questions, and they need to be addressed too.”
While these may be less immediately pressing problems for PG&E than preventing fires, backing up high-outage-risk customers and maintaining its financial viability, they won’t get any easier to solve by postponing debate over them, AEE’s Rai said.
“It’s really important for PG&E to come out with a strong plan for how it’s facing these challenges, how it’s aligned with the state’s plans, and how it’s going to meet the objectives that state policymakers have set for them,” she said. “There are a lot more questions than answers right now. But the time to have that conversation is right now.”