Tag Archives: PG&E

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

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.

A cautionary tale to communities negotiating with energy project developers

The City of Davis signed a lease option agreement on March 24 with a start up solar development company headed by a former CEO of a large renewable firm. How the negotiation process reflected a lack of sufficient knowledge on the part of the City staff is instructive to other cities and counties about the need to be fully informed when a renewable project developer approaches them about land or power deals. In this case the City gave away the potential for gaining tens of millions of dollars.

The agreement was negotiated in a series of closed sessions starting December 17 and approved in a rush under the premise that the project faced an April 15 deadline for submitting its interconnection application to the California Independent System Operator (CAISO). The deal immediately unleashed a storm of outrage from many knowledgeable citizens (several who are appointed city commission members) and the City responded soon after with a press release and “Q&A” that did little to quell the uproar. Two City Councilmembers then wrote an additional defense of the deal. The City’s Utilities Commission voted 5-2 to recommend that the City Council rescind the agreement. A request to “cure and correct” under the Brown Act was then filed April 23 by a group of citizens (including me).

Ashley Feeney, City Assistant City Manager, claimed at the Utilities Commission special meeting April 22 that the BrightNight lease option agreement and term sheet have “favorable terms to the City.”  No doubt it’s favorable to the developer — a low-cost lease option and lease terms at the average rate for agricultural use for a multi-million dollar solar energy project with no strings attached. The staff’s naivete comes through a close reading of the entire agreement.

What are so many people missing that makes this project so favorable to the City as the Council and staff claim? While the process of signing the lease option agreement with the developer was (a) unnecessarily secretive, (b) precluded useful citizen input, and (c) likely violated state law in several ways— at its core, the agreement is simply a bad deal. The City either failed to carry out its due diligence, or was seriously misled by the developer, or both. As a result, the City likely gave away millions of dollars over the next 50 plus years, failed to guarantee any clean energy for the City and failed to protect the City fully at the end of the project life. While the City may desire local renewable power, the agreement lacks any real commitment to advance the City’s climate goals while gaining local benefits.

The agreement (1) underprices both the lease option and the lease prices relative the actual value to the developer, (2) lacks any guarantee of plant power being sold to Davis or VCEA, much less at favorable terms, (3) lacks appropriate protection that sufficient funds will be available to decommission the plant, and (4) forsakes opportunities for more valuable alternative uses for those parcels for at least the next five years.

The first of those misunderstandings was that there was, in fact, no need for the developer to have site control for the CAISO interconnection process.  Whatever developer’s “standard” practice is has no bearing on how and what the City should decide in its own interest. The CAISO interconnection process requires either (1) a $250,000 refundable deposit regardless of site control plus a $150,000 study deposit, if the project is submitting under the Cluster application which is due by April 15, or (2) with site control there is no deposit except the same $150,000 study deposit under the Independent Study Process and no deadline. In this case, the City has essentially gifted the developer $225,000 by providing site control at a steep discount. The developers appears to have exploited the City’s lack of knowledge about the interconnection process by conflating the two processes.

Instead the City should have priced the lease option to reflect the developer’s value, not the City’s. That means that handing over the site control was worth the avoided carrying cost of that deposit each year. With a standard rate of return of at least 10% on real estate investments, that amounts to $25,000 per year, which translates into $106 per acre.  In any case, the minimum opportunity cost to the City is either using it for annual row crop agriculture or reflecting the delay in other uses such as organic waste processing, both of which far exceed the $20 per acre in the lease option.

The City should have specified that the project sell output only to either the City or Valley Clean Energy Authority (VCEA) at a favorable price. The developer is now in the driver’s seat and can solicit bids from the entire range of utilities and load-serving entities such as PG&E, SMUD and other CCAs. This will make the cost of this power more expensive even if Davis or VCEA wins the power output. But now that the agreement has been executed, the City no longer has any leverage in either the lease terms or an energy sale to VCEA, because it cannot force the developer into an agreement.

The City could have specified that the output be wheeled to City accounts through PG&E’s RES-BCT tariff that is available to public agencies. A wholesale solar power contract for the project is unlikely to be much more than 5 cents per kilowatt-hour. In contrast, if the project was structured to take advantage of the the power savings under RES-BCT would amount to over 8 cents per kilowatt-hour—at least 60% higher. (At least 35 megawatts is still available for subscription.) This benefit amounts to over $1.2 million per year at current PG&E rates, compared to an expected annual lease payment under the current lease agreement ranging from $40,000 to $80,000. The gain in value over 50 years could be $52 million in nominal dollars or $21 million in net present value. That delivers an equivalent to a lease rate of $5,000 per acre, not $340 or less.

Even if the City did not use the power output, it should have negotiated a lease price based on either (1) the value of rezoned commercial and industrial land since the developer would have to get that zoning designation to develop its project elsewhere, or (2) the highest agricultural value (not the average for the county). For agricultural land, the value a City commissioner and orchard farmer has calculated is $1,688 to $2,250 per acre, or four to five times higher than the rate that the City negotiated based on a naïve calculation.

Further, the term sheet specifies that the developer pay the property taxes. However, the value of the parcels will not increase if the project is built prior to the 2025 because of the solar property exclusion in state law. The County will receive a short term boost in sales tax revenues from plant construction, but the City will not receive any share of that since its outside City boundaries. The City could have negotiated an in-lieu payment from the developer based on the added property value.

While the lease agreement pays lip service to the developer’s responsibility for decommissioning and disposing of the project at the end of its useful life, the term sheet has no provision prohibiting the developer from declaring bankruptcy for its limited liability corporation (LLC) and just walking away. Since the project will have no income at the end its life, and the entity owning the plant is legally separate from primary development firm (or its successor), the obvious step is to simply dissolve the LLC through a bankruptcy.  Such a step would leave the plant for the City to dispose of at significant expense (likely more than $1 million at today’s prices.)  This will wipe out half of the current lease revenues. That is the route that PG&E Corporation took in 2001 when its subsidiary, Pacific Gas and Electric Company, declared bankruptcy in 2001, leaving the bill of the energy crisis to ratepayers instead of shareholders. The City failed to require a surety bond that would cover those costs. Such bonds or other endowments are typical for projects of this type.

An additional consideration that appears to have been ignored is that The City has been looking at other higher value uses of the site such as organics waste disposal or habitat preservation and restoration. These have been under study at several City Commissions, but now those efforts have been aborted.

Finally, some of have defended maintaining the agreement because abrogating it could expose the City to significant legal liability. The developer at this time cannot sue for more than its demonstrated losses, and since it does not yet have a power purchase agreement, it has no future income stream to point to. At most, the liability is the $150,000 deposit with the CAISO  plus a few thousand dollars expended preparing and submitting the interconnection application (which in fact can be remediated with a $250,000 refundable deposit).

The agreement still faces several hurdles including whether the process violated California’s Brown Act, approval with any Yolo County zoning changes, conformance between the agreement and CAISO interconnection requirements, and winning with an RFO bid.

Even if the City believes that it is compelled to go forward with this agreement, it should admit that it made a series of serious mistakes and needs to review its practices and processes that caused this mess. Unfortunately, it does not seem that the City could have done any worse in these negotiations.

Richard McCann testified at the California Public Utilities Commission on behalf of Santa Clara and San Joaquin counties about their RES-BCT projects, and analyzed solar net metering arrangements for agricultural and mobilehome park clients. He evaluated the fiscal impacts of solar projects on San Luis Obispo, San Benito and Inyo counties, and projected the costs of the Desert Renewable Energy Conservation Plan for the California Energy Commission. He is a member of the Natural Resources Commission, former member of the Utilities Commission, and was recently recognized with  the City’s 2020 Environmental Recognition Award for serving on the Technical Advisory Subcommittee of the Community Choice Energy Advisory Committee, leading to formation of Valley Clean Energy.

Victory for mobilehome park residents and owners

The California Public Utilities Commission (CPUC) authorized the continuance for the next 10 years of the program that converts ownership of privately-held utility systems in mobilehome parks to that of investor-owned energy utilities, including Pacific Gas & Electric, Southern California Edison, San Diego Gas and Electric and Southern California Gas. Of the 400,000 mobilehome spaces in California, over 300,000 are currently served by “master metered” systems that are owned and maintained by the park owner.

Most of these systems were built more than 40 years ago, although many have been replaced periodically. This program aims to transfer all of these systems to standard utility service. Due to the age of these systems, some engineered to only last a dozen years initially because these parks were intended as “transitional” land uses, concerns about safety have been paramount. This program will bring these systems up to the standards of other California ratepayers.

Along with improved safety, residents will gain greater access to energy efficiency and other energy management programs that they already fund at the utilities, and smoother billing. Residents also will have access to time of use rates that has been precluded by the intervening master meter. Park owners will avoid the increasing complexity of billing, system maintenance and safety inspections and filings, and future costs of system replacement. In addition, park owners have been inadequately compensated through utility rates for maintaining those systems, and have resistance in recovering related costs through rents.

I have been working with one of my clients, Western Manufactured Housing Communities Association (WMA) since 1997 to achieve this goal. The momentum finally shifted in 2014 when we convinced the utilities that making these investments could be profitable. First athree-year pilot program was authorized, and this recent decision builds on that.

 

Is PG&E really a “recidivist felon”?

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.

Should CCAs accept a slice of Diablo Canyon power?

The northern California community choice aggregators (CCAs) are considering a offer from PG&E to allocate to each CCA a proportionate share of parts of its portfolio, including the Diablo Canyon nuclear generation station. Many CCA boards are hearing from anti-nuclear activists to deny this offer, both for moral reasons and the belief that such a rejection will somehow pressure PG&E financially. The first set of concern is beyond my professional expertise, but their reasoning on the economic and regulatory issues is incorrect.

  • CCAs buy a substantial portion of their generation (the majority for many of them) from the California Independent System Operator (CAISO) energy markets. PG&E schedules Diablo Canyon into those CAISO markets and under the current CAISO tariffs, nuclear generation is a “must take” resource that the CAISO can’t turn back. So the entire output of Diablo Canyon is scheduled into the CAISO market (without any bidding process), PG&E is paid the market clearing price (MCP) for that Diablo power, and the CCAs buy that mix of nuclear power at the MCP. There is no discretion for either the CAISO or the CCAs in taking excess power from Diablo. There is no “lifeline” for Diablo that the CCAs have any control over under current legal and regulatory parameters.
  • CCAs already pay for a proportionate share of Diablo Canyon equal to the CCAs share of overall load. That payment is broken into two parts (and maybe a third): 1) the purchase of energy from the CAISO at the MCP and 2) the stranded capital and operating costs above the MCP in the PCIA. (CCAs also may be paying for a share of the resource adequacy, but I haven’t thought through that one.) Thus, if the CCAs receive credit for the energy that they are already paying for, the energy portion essentially comes as “free”. In addition, because CCAs currently pay for the remaining share of Diablo costs, but get no energy credit for that in the PCIA calculation, then that credit is in the PCIA is also “free”. In addition, the CCAs gain credit for Diablo’s GHG-free generation (as recognized in the Air Resources Board GHG allowance program) as LSE’s for no extra cost, or for “free.” The bottom line is when the CCAs gain credit for products that they are already paying for, receipt of those products is for “free.”
  • Accepting this deal will not solve ALL of the CCAs problems, but that’s a false goal. That was never the intent. It does however give the CCAs a respite to get through the period until Diablo retires. One needs to recognize that this provides some of the needed relief.
  • Finally, there’s never any certainty over any large deal. Uncertainty should not freeze decision making. The uncertainty about the PCIA going forward is equally large and perhaps offsetting. The risks should be identified, discussed, considered and addressed to the extent possible. But that’s different than simply nixing the deal without addressing the other large risk. Naively believing that Diablo can be closed in short order (especially with the COVID crisis) is not a true risk management strategy.

From these points, we can come to these conclusions:

  1. Whether the CCAs accept or reject the nuclear offer has NO impact on PG&E’s revenue stream. The decisions that the CCAs face are entirely about whether the CCAs can lower their costs and gain some additional GHG reduction credits that they are already paying for (in other words, reduce their subsidies of bundled customers.) Nothing that the CCAs decide will affect the closure date of Diablo. If the CCAs reject the allocations, it will simply be business as usual to the full closures in 2025. Any other interpretation doesn’t reflect the current regulatory environment at the CPUC which are unlikely to change (and even that is unknown) until enough commissioners’ five-year terms roll over.
  2. The system can only be changed by legislative and regulatory action. That means that the CCAs must make the most prudent financial decisions within the current context rather than making a purely symbolic gesture that is financially adverse and will do nothing to change the BAU practice. A wise decision would consider what is the true impact of the action on
  3. Finally, early closure of Diablo will NOT remove the invested capital cost from PG&E’s ratebase, which is what drives the PCIA. After the plant is closed, activists will ALSO have to show that the INVESTMENT in the plant was imprudent and should not have been allowed. Given the long history on decisions and settlements in Diablo investment costs and the inclusion of recovery of Diablo costs in both AB1890 and AB1X at the beginning and end of the energy crisis, that is an impossible task. Only a constitutional amendment through the initiative process could possibly lead to such an action, and even that would have to survive a court challenge that probably would push past 2024.

I want to finish with what I think is a very important point that has been overlooked by the activists: The effort to close Diablo Canyon has won. Activists might not like the timeline of that victory, but it is a victory nevertheless that looked unachievable prior to 2016. It’s worthwhile considering whether the added effort for what will be for a variety of reasons little gain is an important question to answer.

Note that Diablo Canyon is already scheduled for closure in 2024 and 2025. A proceeding to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably wouldn’t open until almost 2021. The actual proceeding would take up to a year, so now we’re to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there’s likely no capital additions avoided by the early closure, so the cost savings would be minimal.

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

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.

We’ve already paid for Diablo Canyon

As I wrote last week, PG&E is proposing that a share of Diablo Canyon nuclear plant output be allocated to community choice aggregators (CCAs) as part of the resolution of issues related to the Integrated Resource Plan (IRP), Resource Adequacy (RA) and Power Charge Indifference Adjustment (PCIA) rulemakings. While the allocation makes sense for CCAs, it does not solve the problem that PG&E ratepayers are paying for Diablo Canyon twice.

In reviewing the second proposed settlement on PG&E costs in 1994, we took a detailed look at PG&E’s costs and revenues at Diablo. Our analysis revealed a shocking finding.

Diablo Canyon was infamous for increasing in cost by more than ten-fold from the initial investment to coming on line. PG&E and ratepayer groups fought over whether to allow $2.3 billion dollars.  The compromise in 1988 was to essentially shift the risk of cost recovery from ratepayers to PG&E through a power purchase agreement modeled on the Interim Standard Offer Number 4 contract offered to qualifying facilities (but suspended as oversubscribed in 1985).

However, the contract terms were so favorable and rich to PG&E, that Diablo costs negatively impacted overall retail rates. These costs were a key contributing factor that caused industrial customers to push for deregulation and restructuring. As an interim solution in 1995 in anticipation of forthcoming restructuring, PG&E and ratepayer groups arrived at a new settlement that moved Diablo Canyon back into PG&E’s regulated ratebase, earning the utilities allowed return on capital. PG&E was allowed to keep 100% of profit collected between 1988 and 1995. The subsequent 1996 settlement made some adjustments but arrived at essentially the same result. (See Decision 97-05-088.)

While PG&E had borne the risks for seven years, that was during the plant startup and its earliest years of operation.  As we’ve seen with San Onofre NGS and other nuclear plants, operational reliability is most at risk late in the life of the plant. PG&E’s originally took on the risk of recovering its entire investment over the entire life of the plant.  The 1995 settlement transferred the risk for recovering costs over the remaining life of the plant back to ratepayers. In addition, PG&E was allowed to roll into rate base the disputed $2.3 billion. This shifted cost recovery back to the standard rate of depreciation over the 40 year life of the NRC license. In other words, PG&E had done an end-run on the original 1988 settlement AND got to keep the excess profits.

The fact that PG&E accelerated its investment recovery over the first seven years and then shifted recovery risk to ratepayers implies that PG&E should be allowed to recover only the amount that it would have earned at a regulated return under the original 1988 settlement. This is equal to the discounted net present value of the net income earned by Diablo Canyon, over both the periods of the 1988 (PPA) and 1995 settlements.

In 1996, we calculated what PG&E should be allowed to recover in the settlement given this premise.  We assumed that PG&E would be allowed to recover the disputed $2.3 billion because it had taken on that risk in 1988, but the net income stream should be discounted at the historic allowed rate of return over the seven year period.  Based on these assumptions, PG&E had recovered its entire $7.7 billion investment by October 1997, just prior to the opening of the restructured market in March 1998.  In other words, PG&E shareholders were already made whole by 1998 as the cost recovery for Diablo was shifted back to ratepayers.  Instead the settlement agreement has caused ratepayers to pay twice for Diablo Canyon.

PG&E has made annual capital additions to continue operation at Diablo Canyon since then and a regulated return is allowed under the regulatory compact.  Nevertheless, the correct method for analyzing the potential loss to PG&E shareholders from closing Diablo is to first subtract $5.1 billion from the plant in service, reducing the current ratebase to capital additions incurred since 1998. This would reduces the sunk costs that are to be recovered in rates from $31 to $3 per megawatt-hour.

Note that PG&E shareholders and bondholders have earned a weighted return of approximately 10% annually on this $5.1 billion since 1998. The compounded present value of that excess return was $18.1 billion by 2014 earned by PG&E.

CCAs don’t undermine their mission by taking a share of Diablo Canyon

Northern California community choice aggregators (CCAs) are considering whether to accept an offer from PG&E to allocate a proportionate share of its “large carbon-free” generation as a credit against the power charge indifference adjustment (PCIA) exit fee.  The allocation would include a share of Diablo Canyon power. The allocation for 2019 and 2020; an extension of this allocation is being discussed on the PCIA rulemaking.

The proposal faces opposition from anti-nuclear and local community activists who point to the policy adopted by many CCAs not to accept any nuclear power in their portfolios. However, this opposition is misguided for several reasons, some of which are discussed in this East Bay Community Energy staff report.

  • The CCAs already receive and pay for nuclear generation as part of the mix of “unspecified” power that the CCAs buy through the California Independent System Operator (CAISO). The entire cost of Diablo Canyon is included in the Total Portfolio Cost used to calculate the PCIA. The CCAs receive a “market value” credit against this generation, but the excess cost of recovering the investment in Diablo Canyon (for which PG&E is receiving double payment based on calculations I made in 1996) is recovered through the PCIA. The CCAs can either continue to pay for Diablo through the PCIA without receiving any direct benefits, or they can at least gain some benefits and potentially lower their overall costs. (CCAs need to be looking at their TOTAL generation costs, not just their individual portfolio, when resource planning.)
  • Diablo Canyon is already scheduled to close Unit 1 in 2024 and Unit 2 in 2025 after a contentious proceeding. This allocation is unlikely to change this decision as PG&E has said that the relicensed plant would cost in excess of $100 per megawatt-hour, well in excess of its going market value. I have written extensively here about how costly nuclear power has been and has yet to show that it can reduce those costs. Unless the situation changes significantly, Diablo Canyon will close then.
  • Given that Diablo is already scheduled for closure, the California Public Utilities Commission (CPUC) is unlikely to revisit this decision. But even so, a decision to either reopen A.16-08-006 or to open a new rulemaking or application would probably take close to a year, so the proceeding probably would not open until almost 2021. The actual proceeding would take up to a year, so now we are to 2022 before an actual decision. PG&E would have to take up to a year to plan the closure at that point, which then takes us to 2023. So at best the plant closes a year earlier than currently scheduled. In addition, PG&E still receives the full payments for its investments and there is likely no capital additions avoided by the early closure, so the cost savings would be minimal.

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

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

electricservicearea

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.