Tag Archives: wildfires

In the LA Times – looking for alternative solutions to storm outages

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I was interviewed by a Los Angeles Times reporter about the recent power outages in Northern California as result of the wave of storms. Our power went out for 48 hours New Year’s Eve and again for 12 hours the next weekend:

After three days without power during this latest storm series, Davis resident Richard McCann said he’s seriously considering implementing his own microgrid so he doesn’t have to rely on PG&E.

“I’ve been thinking about it,” he said. McCann, whose work focuses on power sector analysis, said his home lost power for about 48 hours beginning New Year’s Eve, then lost it again after Saturday for about 12 hours.

While the storms were severe across the state, McCann said Davis did not see unprecedented winds or flooding, adding to his concerns about the grid’s reliability.

He said he would like to see California’s utilities “distributing the system, so people can be more independent.”

“I think that’s probably a better solution rather than trying to build up stronger and stronger walls around a centralized grid,” McCann said.

Several others were quoted in the article offering microgrids as a solution to the ongoing challenge.

Widespread outages occurred in Woodland and Stockton despite winds not being exceptionally strong beyond recent experience. Given the widespread outages two years ago and the three “blue sky” multi hour outages we had in 2022 (and none during the September heat storm when 5,000 Davis customers lost power), I’m doubtful that PG&E is ready for what’s coming with climate change.

PG&E instead is proposing to invest up to $40 billion in the next eight years to protect service reliability for 4% of their customers via undergrounding wires in the foothills which will raise our rates up to 70% by 2030! There’s an alternative cost effective solution that would be 80% to 95% less sitting before the Public Utilities Commission but unlikely to be approved. There’s another opportunity to head off PG&E and send some of that money towards fixing our local grid coming up this summer under a new state law.

While winds have been strong, they have not been at the 99%+ range of experience that should lead to multiple catastrophic outcomes in short order. And having two major events within a week, plus the outage in December 2020 shows that these are not statistically unusual. We experienced similar fierce winds without such extended outages. Prior to 2020, Davis only experienced two extended outages in the previous two decades in 1998 and 2007. Clearly the lack of maintenance on an aging system has caught up with PG&E. PG&E should reimagine its rural undergrounding program to mitigate wildfire risk to use microgrids instead. That will free up most of the billons it plans to spend on less than 4% of its customer base to instead harden its urban grid.

PG&E takes a bold step on enabling EV back up power, but questions remain

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PG&E made exciting announcements about partnerships with GM and Ford last week to test using electric vehicles (EVs) for backup power for residential customers. (Ford also announced an initiative to create an open source charging standard.) PG&E also announced an initiative to install circuit breakers that facilitate use of onsite backup power. PG&E is commended for stepping forward to align its corporate strategy with the impending technology wave that could increase consumer energy independence.

I wrote about the promise of EVs in this role (“Electric vehicles as the next smartphone”) when I was struck by Ford’s F-150 Lightning ads last summer and how the consumer segment that buys pickups isn’t what we usually think of as the “EV crowd.” These initiatives could be game changers.

That said, several questions arise about PG&E’s game plan and whether the utility is still planning to hold customers captive:

  • How does PG&E plan to recover the costs for what are “beyond the meter” devices that typically is outside of what’s allowed? And how are the risks in these investments to be shared between shareholders and ratepayers? Will PG&E get an “authorized” rate of return with default assurances of costs being approved for recovery from ratepayers? How will PG&E be given appropriate incentives on making timely investments with appropriate risk, especially given the utility’s poor track record in acquiring renewable resources?
  • What will be the relationships between PG&E and the participating auto manufacturers? Will the manufacturers be required to partner with PG&E going forward? Will the manufacturers be foreclosed from offering products and services that would allow customers to exit PG&E’s system through self generation? Will PG&E close out other manufacturers from participating or set up other access barriers that prevent them from offering alternatives?
  • Delivering PG&E’s “personal microgrid backup power transfer meter device” is a good first step, but it requires disconnecting the solar panels to use, which means that it only support fossil fueled generators and grid-connected batteries. This device needs a switch for the solar panels as well. Further, it appears the device will only be available to customers who participate in PG&E’s Residential Generator and Battery Rebate Program. Can PG&E continue to offer this feature to vendors who offer only fossil-fueled generators? How will PG&E mitigate the local air pollution impacts from using fossil-fueled back up generators (BUGs) for extended periods? (California already has 8,000 megawatts of BUGs.)
  • How will these measures be integrated with the planned system reinforcements in PG&E’s 2022 Wildfire Mitigation Plan Update to reduce the costs of undergrounding lines? Will PG&E allow these back up sources and devices for customers who are interested in extended energy independence, particularly those who want to ride out a PSPS event?
  • How will community choice aggregators (CCAs) or other local governments participate? Will communities be able to independently push these options to achieve their climate action and adaptation plan (CAAP) goals?

A cheaper wildfire mitigation solution: using microgrids instead of undergrounding

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PG&E released its 2022 Wildfire Mitigation Plan Update (2022 WMPU) That plan calls for $6 billion of capital investment to move 3,600 miles of underground by 2026. This is just over a third of the initial proposed target of 10,000 miles. Based on PG&E’s proposed ramping up, the utility would reach its target by 2030.

One alternative that could better control costs would be to install community and individual microgrids. Microgrids are likely more cost effective and faster means of reducing wildfire risk and saving lives. I wrote about how to evaluate this choice for relative cost effectiveness based on density of load and customers per mile of line.

Microgrids can mitigate wildfire risk by the utility turning off overhead wire service for extended periods, perhaps weeks at a time, during the highest fire risk periods. The advantage of a periodically-islanded microgrid is 1) that the highest fire risk coincides with the most solar generation so providing enough energy is not a problem and 2) the microgrids also can be used during winter storms to better support the local grid and to ride out shorter outages. Customers’ reliability may degrade because they would not have the grid support, but such systems generally have been quite reliable. In fact, reliability may increase because distribution grid outages are about 15 times more likely than system or regional outages.

The important question is whether microgrids can be built much more quickly than undergrounding lines and in particular whether PG&E has the capacity to manage such a buildout at a faster rate? PG&E has the Community Microgrid Enablement Program. The utility was recently authorized to build several isolated microgrids as an alternative to rebuilding fire-damaged distribution lines to isolated communities. Turning to local governments to manage many different construction projects likely would improve this schedule, like how Caltrans delegates road construction to counties and cities.

Controlling the costs of wildfire mitigation

Based on the current cost of capital this initial undergrounding phase will add $1.6 billion to annual revenue requirements or an additional 8% above today’s level. This would be on top of PG&E request in its 2023 General Rate Case for a 48% increase in distribution rates by 2023 and 78% increase by 2026, and a 31% increase in overall bundled rates by 2023 and 43% by 2026. The 2022 WMPU would take the increase to over 50% by 2026 (and that doesn’t’ include the higher maintenance costs). That means that residential rates would increase from 28.7 cents per kilowatt-hour today (already 21% higher than December 2020) to 36.4 cents in 2026. Building out the full 10,000 miles could lead to another 15% increase on top of all of this.

Turning to the comparison of undergrounding costs to microgrids, these two charts illustrate how to evaluate the opportunities for microgrids to lower these costs. PG&E states the initial cost per mile for undergrounding is $3.75 million, dropping to $2.5 million, or an average of $2.9 million. The first figure looks at community scale microgrids, using National Renewable Energy Laboratory (NREL) estimates. It shows how the cost effectiveness of installing microgrids changes with density of peak loads on a circuit on the vertical axis, cost per kilowatt for a microgrid on the horizontal axis, and each line showing the division where undergrounding is less expensive (above) or microgrids are less expensive (below) based on the cost of undergrounding. As a benchmark, the dotted line shows the average load density in the PG&E system, combined rural and urban. So in average conditions, community microgrids are cheaper regardless of the costs of microgrids or undergrounding.

The second figure looks at individual residential scale microgrids, again using NREL estimates. It shows how the cost effectiveness of installing microgrids changes with customer density on a circuit on the vertical axis, cost per kilowatt for a microgrid on the horizontal axis, and each line showing the division where undergrounding is less expensive (above) or microgrids are less expensive (below). As a benchmark, the dotted line shows the average customer density in the PG&E system, combined rural and urban. Again, residential microgrids are less expensive in most situations, especially as density falls below 75 customers per mile.

A movement towards energy self-sufficiency is growing in California due to a confluence of factors. PG&E’s WMPU should reflect these new choices in manner that can reduce rates for all customers.

(Here’s my testimony on this topic filed by the California Farm Bureau in PG&E’s 2023 General Rate Case on its Wildfire Management Plan Update.)

Comparing cost-effectiveness of undergrounding vs. microgrids to mitigate wildfire risk

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Pacific Gas & Electric has proposed to underground 10,000 miles of distribution lines to reduce wildfire risk, at an estimated cost of $1.5 to $2 million per mile. Meanwhile PG&E has installed fast-trip circuit breakers in certain regions to mitigate fire risks from line shorts and breaks, but it has resulted in a vast increase in customer outages. CPUC President Batjer wrote in an October 25 letter to PG&E, “[s]ince PG&E initiated the Fast Trip setting practice on 11,500 miles of lines in High Fire Threat Districts in late July, it has caused over 500 unplanned power outages impacting over 560,000 customers.” She then ordered a series of compliance reports and steps. The question is whether undergrounding is the most cost-effective solution that can be implemented in a timely manner.

A viable alternative is microgrids, installed at either individual customers or community scale. The microgrids could be operated to island customers or communities during high risk periods or to provide backup when circuit breakers cut power. Customers could continue to be served outside of either those periods of risk or weather-caused outages.

Because microgrids would be installed solely for the purpose of displacing undergrounding, the relative costs should be compared without considering any other services such as energy delivered outside of periods of fire risk or outages or increased green power.

I previously analyzed this question, but this updated assessment uses new data and presents a threshold at which either undergrounding or microgrids is preferred depending on the range of relative costs.

We start with the estimates of undergrounding costs. Along with PG&E’s stated estimate, PG&E’s 2020 General Rate Case includes a settlement agreement with a cost of $4.8 million per mile. That leads to an estimate of $15 to $48 million. Adding in maintenance costs of about $400 million annually, this revenue requirement translates to a rate increase of 3.2 to 9.3 cents per kilowatt-hour.

For microgrid costs, the National Renewable Energy Laboratory published estimated ranges for both (1) commercial or community scale projects of 1 megawatt with 2.4 megawatt-hours of storage and (2) residential scale of 7 kilowatts with 20 kilowatt-hours of storage. For larger projects, NREL shows ranges of $2.07 to $2.13 million; we include an upper end estimate double of NREL’s top range. For residential; the range is $36,000 to $38,000.

Using this information, we can make comparisons based on the density of customers or energy use per mile of targeted distribution lines. In other words, we can determine if its more cost-effective to underground distribution lines or install microgrids based on how many customers or how much load is being served on a line.

As a benchmark, PG&E’s average system density per mile of distribution line is 50.6 customers and 166 kW (or 0.166 MW).

The table below shows the relative cost effectiveness for undergrounding compared to community/commercial microgrids. If the load density falls below the value shown, microgrids are more cost effective. Note that the average density across the PG&E service area is 0.166 MW which is below any of the thresholds. That indicates that such microgrids should be cost-effective in most rural areas.

The next table shows the relative cost effectiveness for individual residential microgrids, and again if the customer density falls below the threshold shown, then microgrids save more costs. The average density for service area is 51 customers per line-mile which reflects the concentration of population in the Bay Area. At the highest undergrounding costs, microgrids are almost universally favored. In rural areas where density falls below 30 customers per line-mile, microgrids are less costly at the lower undergrounding costs.

PG&E has installed two community-scale microgrids in remote locations so far, and reportedly considering 20 such projects. However, PG&E fell behind on those projects, prompting the CPUC to reopen its procurement process in its Emergency Reliability rulemaking. In addition, PG&E has relied heavily on natural gas generation for these.

PG&E simply may not have the capacity to construct either microgrids or install undergrounded lines in a timely manner solely through its organization. PG&E already is struggling to meet its targets for converting privately-owned mobilehome park utility systems to utility ownership. A likely better choice is to rely on local governments working in partnership with PG&E to identify the most vulnerable lines to construct and manage these microgrids. The residential microgrids would be operated remotely. The community microgrids could be run under several different models including either PG&E or municipal ownership.

Vegetation maintenance the new “CFL” for wildfire management

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PG&E has been aggressively cutting down trees as part of its attempt to mitigate wildfire risk, but those efforts may be creating their own risks. Previously, PG&E has been accused of just focusing numeric targets over effective vegetation management. This situation is reminiscent of how the utilities pursued energy efficiency prior to 2013 with a seemingly single-minded focus on compact fluorescent lights (CFLs). And that focus did not end well, including leading to both environmental degradation and unearned incentives for utilities.

CFLs represented about 20% of the residential energy efficiency program spending in 2009. CFLs were easy for the utilities–they just delivered steeply discounted, or even free, CFLs to stores and they got to count each bulb as an “energy savings.” By 2013, the CPUC ordered the utilities to ramp down spending on CFLs as a new cost-effective technology emerged (LEDs) and the problem of disposing of mercury in the ballasts of CFLs became apparent. But more importantly, it turned out that CFLs were just sitting in closets, creating much fewer savings than estimated. (It didn’t help that CFLs turned out to have a much shorter life than initially estimated as well.) Even so, the utilities were able claim incentives from the California Public Utilities Commission. Ultimately, it became apparent that CFLs were largely a mistake in the state’s energy efficiency portfolio.

Vegetation management seems to be the same “easy number counting” solution that the utilities, particularly PG&E, have adopted. The adverse consequences will be significant and it won’t solve the problem in the long. Its one advantage is that it allows the utilities to maintain their status quo position at the center of the utility network.

Other alternatives include system hardening such as undergrounding or building microgrids in rural communities to allow utilities to deenergize the grid while maintaining local power. The latter option appears to be the most cost effective solution, but it is also the most threatening to the current position of the incumbent utility by giving customers more independence.

PG&E’s bankruptcy—what’s happened and what’s next?

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The wildfires that erupted in Sonoma County the night of October 8, 2017 signaled a manifest change not just limited to how we must manage risks, but even to the finances of our basic utility services. Forest fires had been distant events that, while expanding in size over the last several decades, had not impacted where people lived and worked. Southern California had experienced several large-scale fires, and the Oakland fire in 1991 had raced through a large city, but no one was truly ready for what happened that night, including Pacific Gas and Electric. Which is why the company eventually declared bankruptcy.

PG&E had already been punished for its poor management of its natural gas pipeline system after an explosion killed nine in San Bruno in 2010. The company was convicted in federal court, fined $3 million and placed on supervised probation under a judge.

PG&E also has extensive transmission and distribution network with more than 100,000 miles of wires. Over a quarter of that network runs through areas with significant wildfire risk. PG&E already had been charged with starting several forest fires, including the Butte fire in 2015, and its vegetation management program had been called out as inadequate by the California Public Utilities Commission (CPUC) since the 1990s. The  CPUC caught PG&E diverting $495 million from maintenance spending to shareholders from 1992 to 1997; PG&E was fined $29 million. Meanwhile, two other utilities, Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) had instituted several management strategies to mitigate wildfire risk (not entirely successful), including turning off “line reclosers” during high winds to avoid short circuits on broken lines that can spark fires. PG&E resisted such steps.

On that October night, when 12 fires erupted, PG&E’s equipment contributed to starting 11 of those, and indirectly at least to other. Over 100,000 acres burned, destroying almost 9,000 buildings and killing 44 people. It was the most destructive fire in history, costing over $14 billion.

But PG&E’s problems were not over. The next year in November 2018, an even bigger fire in Butte County, the Camp fire, caused by a failure of a PG&E transmission line. That one burned over 150,000 acres, killing 85, destroying the community of Paradise and costing $16 billion plus. PG&E now faced legal liabilities of over $30 billion, which exceeds PG&E’s invested capital in its system. PG&E was potentially upside down financially.

The State of California had passed Assembly Bill 1054 that provided a fund of $21 billion to cover excess wildfire costs to utilities (including SCE and SDG&E), but it only covered fires after 2018. The Wine Country and Camp fires were not included, so PG&E faced the question of how to pay for these looming costs. Plus PG&E had an additional problem—federal Judge William Alsup supervising its parole stepped in claiming that these fires were a violation of its parole conditions. The CPUC also launched investigations into PG&E’s safety management and potential restructuring of the firm. PG&E faced legal and regulatory consequences on multiple fronts.

PG&E Corp, the holding company, filed for Chapter 11 bankruptcy on January 14, 2019. PG&E had learned from its 2001 bankruptcy proceeding for its utility company subsidiary that moving its legal and regulatory issues into the federal bankruptcy court gave the company much more control over its fate than being in multiple forums. Bankruptcy law afforded the company the ability to force regulators to increase rates to cover the costs authorized through the bankruptcy. And PG&E suffered no real consequences with the 2001 bankruptcy as share prices returned, and even exceeded, pre-filing levels.

As the case progressed, several proposals, some included in legislative bills, were made to take control of PG&E from its shareholders, through a cooperative, a state-owned utility, or splitting it among municipalities. Governor Gavin Newsom even called on Warren Buffet to buy out PG&E. Several localities, including San Francisco, made separate offers to buy their jurisdictions’ grid. The Governor and CPUC made certain demands of PG&E to restructure its management and board of directors, to which PG&E responded in part. PG&E changed its chief executive officer, and its current CEO, Bill Johnson, will resign on June 30. The Governor holds some leverage because he must certify that PG&E has complied by June 30, 2020 with the requirements of Assembly Bill 1054 that authorizes the wildfire cost relief fund for the utilities.

Meanwhile, PG&E implemented a quick fix to its wildfire risk with “public safety power shutoffs” (PSPS), with its first test in October 2019, which did not fare well. PG&E was accused of being excessive in the number of customers (over 800,000) and duration and failing to coordinate adequately with local governments. A subsequent PSPS event went more smoothly, but still had significant problems. PG&E says that such PSPS events will continue for the next decade until it has sufficiently “hardened” its system to mitigate the fire risk. Such mitigation includes putting power lines underground, changing system configuration and installing “microgrids” that can be isolated and self sufficient for short durations. That program likely will cost tens of billions of dollars, potentially increasing rates as much as 50 percent. One question will be who should pay—all ratepayers or those who are being protected in rural areas?

PG&E negotiated several pieces of a settlement, coming to agreements with hedge-fund investors, debt holders, insurance companies that pay for wildfire losses by residents and businesses, and fire victims. The victims are to be paid with a mix of cash and stock, with a face value of $13.5 billion; the victims are voting on whether to accept this agreement as this article is being written. Local governments will receive $1 billion, and insurance companies $11 billion, for a total of $24.5 billion in payouts.  PG&E has lined up $20 billion in outside financing to cover these costs. The total package is expected to raise $58 billion.

The CPUC voted May 28 to approve PG&E’s bankruptcy plan, along with a proposed fine of $2 billion. PG&E would not be able to recover the costs for the 2017 and 2018 fires from ratepayers under the proposed order. The Governor has signaled that he is likely to also approve PG&E’s plan before the June 30 deadline.

PG&E is still asking for significant rate increases to both underwrite the AB 1054 wildfire protection fund and to implement various wildfire mitigation efforts. PG&E has asked for a $900 million interim rate increase for wildfire management efforts and a settlement agreement in its 2020 general rate case calls for another $575 million annual ongoing increase (with larger amounts to be added in the next three years). These amount to a more than 10 percent increase in rates for the coming year, on top of other rate increases for other investments.

And PG&E still faces various legal difficulties. The utility pleaded guilty to 85 chargesof manslaughter in the Camp fire, making the company a two-time felon. The federal judge overseeing the San Bruno case has repeatedly found PG&E’s vegetation management program wanting over the last two years and is considering remedial actions.

Going forward, PG&E’s rates are likely to rise dramatically over the next five years to finance fixes to its system. Until that effort is effective, PSPS events will be widespread, maybe for a decade. On top of that is that electricity demand has dropped precipitously due to the coronavirus pandemic shelter in place orders, which is likely to translate into higher rates as costs are spread over a smaller amount of usage.

Is PG&E really a “recidivist felon”?

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TURN, the residential ratepayer intervenor group, submitted a comment letter to the California Public Utilities Commission (CPUC) in Pacific Gas and Electric’s (PG&E) bankruptcy investigation proceeding (I.19-09-016). TURN has some harsh statements asking for denial of recovery of some large expenses, including wildfire victim payments and legal fees. One particular passage caught my attention:

The stark truth is that PG&E is a recidivist felon that has caused multiple
major catastrophes within the space of a decade.

I looked up the definition on Wikipedia. (There are other definitions that differ some.)

Recidivism is the act of a person repeating an undesirable behavior after they have either experienced negative consequences of that behavior, or have been trained to extinguish that behavior. It is also used to refer to the percentage of former prisoners who are rearrested for a similar offense.

But does “recidivist” apply in this situation for this reason: Has PG&E really suffered negative consequences from its previous behavior? So far, despite being convicted of felonies twice in the last decade, PG&E has been fined a total of $6.5 million for the San Bruno gas line explosion and the Camp Fire, which is equal to just over 4 hours of revenues for PG&E, and no one has gone to prison. PG&E continues to hold its franchise with few restrictions over most of northern California, and it appears headed for exiting bankruptcy by June 30 with a favorable finance plan in which current shareholders still hold most of the equity. It’s also not obvious how PG&E has been “trained” to extinguish its behavior, although the CPUC has instituted more oversight.

So, it’s not clear where and how PG&E has suffered significant negative consequences for its criminal acts, unless you consider “flea bites” as real punishment.  To the contrary, PG&E has turned each of these events into money making enterprises.  The first was by catching up on its deferred natural gas pipeline maintenance that it should have been spending on for decades. Instead, the CPUC could have simply ordered that the deferred spending be taken from past revenues. The second is the added investment of billions in hardening the rural distribution system and setting up back up generation in danger areas. That will add hundreds of millions or even a couple billion to annual revenues, all delivering a 10%+ return to company shareholders. Instead of negative consequences, PG&E has been able to turn these convictions into positive financial gains for its investors.

Public takeover of PG&E isn’t going to solve every problem

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This article in the Los Angeles Times about what a public takeover of PG&E appears to take on uses the premise that such a step would lead to lower costs, more efficiencies and reduced wildfire risks. These expectations have never been realistic, and shouldn’t be the motivation for such an action. Instead, a public takeover would offer these benefits and opportunities:

  • While the direct costs of constructing and repairing the grid would likely be about the same (and PG&E has some of the highest labor costs around), the cost to borrow and invest the needed funds would be as much as 30% less. That’s because PG&E weighted average cost of capital (debt and shareholder equity) is around 8% per annum while muncipal debt is 5% or less.
  • Ratepayers are already repaying shareholders and creditors for their investments in the utility system. Buying PG&E’s system would simply be replacing those payments with payments to creditors that hold public bonds. Similar to the cost of fixing the grid, this purchase should reduce the annual cost to repay that debt by 30%.
  • And along these lines, utility shareholders have borne little of the costs from these types of risks. Shareholders supposedly get a premium on their investment returns for these “risks” but when asked for examples of large scale disallowances, none of the utilities could provide significant examples. If ratepayers are already bearing all of those risks, then they should get all of the investment benefits as well.
  • Direct public oversight will eliminate a layer of regulation that PG&E has used to impede effective oversight and deflect responsibility. To some extent regulation by the California Public Utilities Commission has been like pushing on a string, with PG&E doing what it wants by “interpreting” CPUC decisions. The result has been a series of missteps by the utility over many decades.
  • A new utility structure may provide an opportunity to renegotiate a number of overly lucrative renewable power purchase agreements that PG&E signed between 2010 and 2015. PG&E failed to properly manage the risk profile of its portfolio because under state law it could pass through all costs of those PPAs once approved by the CPUC. PG&E’s shareholders bore no risk, so why consider that risk? There are several possible options to addressing this issue, but PG&E has little incentive to act.
  • A publicly-owned utility can work more closely with local governments to facilitate the evolution of the energy system to meet climate change challenges. As a private entity with restrictions on how it can participate in customer-side energy management, PG&E cannot work hand-in-glove with cities and counties on building and transportation transformation. PG&E right now has strong incentives to prevent further defections away from its grid; public utilities are more likely to accept these defections with the possibility that the stranded asset costs will be socialized.

The risks of wildfire damages and liabilities are unlikely to change substantially (except if the last point accelerates distributed energy resource investment). But the other benefits and opportunities are likely to make these costs lower.

Microgrids could cost 10% of undergrounding PG&E’s wires

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One proposed solution to reducing wildfire risk is for PG&E to put its grid underground. There are a number of problems with undergrounding including increased maintenance costs, seismic and flooding risks, and problems with excessive heat (including exploding underground vaults). But ignoring those issues, the costs could be exorbitant-greater than anyone has really considered. An alternative is shifting rural service to microgrids. A high-level estimate shows that using microgrids instead could cost less than 10% of undergrounding the lines in regions at risk. The CPUC is considering a policy shift to promote this type of solution and has new rulemaking on promoting microgrids.

We can put this in context by estimating costs from PG&E’s data provided in its 2020 General Rate Case, and comparing that to its total revenue requirements. That will give us an estimate of the rate increase needed to fund this effort.

PG&E has about 107,000 miles of distribution voltage wires and 18,500 in transmission lines. PG&E listed 25,000 miles of distribution lines being in wildfire risk zones. The the risk is proportionate for transmission this is another 4,300 miles. PG&E has estimated that it would cost $3 million per mile to underground (and ignoring the higher maintenance and replacement costs). And undergrounding transmission can cost as much as $80 million per mile. Using estimates provided to the CAISO and picking the midpoint cost adder of four to ten times for undergrounding, we can estimate $25 million per mile for transmission is reasonable. Based on these estimates it would cost $75 billion to underground distribution and $108 billion for transmission, for a total cost of $183 billion. Using PG&E’s current cost of capital, that translates into annual revenue requirement of $9.1 billion.

PG&E’s overall annual revenue requirement are currently about $14 billion and PG&E has asked for increases that could add another $3 billion. Adding $9.1 billion would add two-thirds (~67%) to PG&E’s overall rates that include both distribution and generation. It would double distribution rates.

This begs two questions:

  1. Is this worth doing to protect properties in the affected urban-wildlands interface (UWI)?
  2. Is there a less expensive option that can achieve the same objective?

On the first question, if we look the assessed property value in the 15 counties most likely to be at risk (which includes substantial amounts of land outside the UWI), the total assessed value is $462 billion. In other words, we would be spending 16% of the value of the property being protected. The annual revenue required would increase property taxed by over 250%, going from 0.77% to 2.0%.

Which turns us to the second question. If we assume that the load share is proportionate to the share of lines at risk, PG&E serves about 18,500 GWh in those areas. The equivalent cost per unit for undergrounding would be $480 per MWh.

The average cost for a microgrid in California based on a 2018 CEC study is $3.5 million per megawatt. That translates to $60 per MWh for a typical load factor. In other words a microgrid could cost one-eighth of undergrounding. The total equivalent cost compared to the undergrounding scenario would be $13 billion. This translates to an 8% increase in PG&E rates.

To what extent should we pursue undergrounding lines versus shifting to microgrid alternatives in the WUI areas? Should we encourage energy independence for these customers if they are on microgrids? How should we share these costs–should locals pay or should they be spread over the entire customer base? Who should own these microgrids: PG&E or CCAs or a local government?

 

 

 

 

Non-Profit Utilities Could Cure What Ails California Electricity

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Severin Borenstein at the Energy Institute at Haas, asks “Would Non-Profit Utilities Cure What Ails California Electricity?” I am posting my response here as that I find his post overlooks several important points and distinctions.

I’ll start by saying I wrote an op-ed in the Sacramento Bee in the early 2000s noting that creating a new municipal utility was not going to deliver the same low rates as existing munis and I’m still aware that such a transfer is unlikely to reduce rates much. But it does change the governance structure in a way that is likely to be more accountable and less influenced by the private interests of utility shareholders. Communities are joining together to push for acquisition of PG&E by a cooperative, which would have a similar governance structure to a municipal utility.

First, the complaint about government is largely about agencies that I will call “ministerial” or “administrative”. These agencies issue permits and licenses or provide social services. In contrast, the government agencies that deliver utility services, which are “enterprises” largely deliver service with few complaints. About 80% of water utilities and almost all wastewater utilities are publicly owned. I work in the water arena as well, and the only utility that I hear complaints about from customers is LADWP (both water and power sides). (The SDCWA-MWD fight is between agencies’ managements, not from customers). On the other hand, all three or California’s electric IOUs are the target of customers’ ire. And the IOU staffs (which I have frequent contact with) are no better than government employees in their responsiveness or competence. One advantage the enterprise agencies have over the ministerial/administrative ones is that they generally pay a higher salary so employees are motivated in much the same way as those in the private sector. Moving from oversight by a ministerial/administrative agency (CPUC) to management by an enterprise utility should overcome the problem of recruiting competent motivated staff.

Second, shareholders shoulder very little risk now, particularly in California. I testified in the IOUs’ rate of return case and we asked for the amount of disallowances that shareholders had to bear over the last two decades. Other than SDG&E’s 2007 wildfire costs due to negligence on the utility’s part, they came pack with amounts that were in the tens of millions, which amounts to less than a 0.1% of their revenues collected over that period. Utilities’ generation investment is now so protected that the CPUC reversed itself last year and removed the 10 year recovery cap from exit fees for generation that the utilities built knowing the cap existed. They are now getting bonus dollars! (Same thing happened with Diablo Canyon in 1996.) Yet the utilities are claiming in that rate case that the return on equity should be increased even further! I have a blog post about how the current return is already too high. (Part 2 is the next day.)  Public ownership in contrast can reduce the return on capital from close to 10% (before tax) to 5% or less, which can cut rates substantially.

We can see how PG&E in particular has been incompetently managed for decades. I posted about its many foibles since the 1960s as well. The supposed incentives and efficiencies of the private sector have failed to materialize for California utilities, and meanwhile we pay higher costs for capital with no real risk mitigation. (Ratepayers still had to pay for PG&E’s debts after the 2000-01 energy crisis, and it looks like the same may happen again.)

Finally, the question arises as to whether municipalizing piecemeal would create inequities. The premise of the statement is that the current economic distribution is equitable. But the fact is that rural residential customers in the wildland/urban interface (WUI) have not been paying their full share of their costs and have been heavily subsidized by urban customers. Those customers in the WUI tend to be better off than average (poor rural customers are more likely to live in agricultural communities that are not subject to the same fire risks and for whom service costs are lower), so we already have an adverse wealth transfer in place. And those subsidies have facilitated expansion of housing into those high risk areas that also encourage longer commutes with more GHG emissions.

The better question is how can the rural service areas be better served in the future without relying on the traditional utility structure? Moving toward microgrids and other DER solutions to improve reliability while reducing fire risk is one solution. Spending a $100 billion on undergrounding lines to be paid for by everyone else is NOT a good solution.