Davis, like many communities, needs a long-term vision

The Davis Vanguard published an article about the need to set out a vision for where the City of Davis wants to go if we want to have a coherent set of residential and commercial development decisions:

How do we continue to provide high quality of life for the residents of Davis, as the city on the one hand faces fiscal shortfalls and on the other hand continues to price the middle class and middle tier out of this community? A big problem that we have not addressed is the lack of any long term community vision. 

The article set out a series of questions that focused on assumptions and solutions. But we should not start the conversation with choosing a growth rate and then picking a set of projects that fit into that projection.

We need to start with asking a set of questions that derive from the thesis of the article:

  • – What is the composition that we want of this community? What type of diversity? How do we accommodate students? What are the ranges of statewide population growth that we need to plan for?
  • – To achieve that community composition, what is the range of target housing price? Given the projected UCD enrollment targets (which are basically out of our control), how much additional housing is needed under different scenarios of additional on campus housing?
  • – What is the jobs mix that supports that community composition under different scenarios? What’s the job mix that minimizes commuting and associated GHG emissions? 
  • – What’s the mix of businesses, jobs and housing that move toward fiscal stability for the City in these scenarios? 
  • – Then in the end we arrive at a set of preferred growth rates that are appropriate for the scenarios that we’ve constructed. We can then develop our general plan to accommodate these preferred scenarios. 

My wife and I put forward one vision for Davis to focus on sustainable food development as an economic engine. I’m sure there’s other viable ideas. We need a forum that dives into these and formulates our economic plan rather than just bumbling along as we seem to be doing now. This is only likely to get worse with the fundamental changes after the pandemic.

I’ll go further to say that one of the roots of this problem is the increasing opaqueness of City decision making. “Playing it safe” is the byword for City planning, just when that’s what is most likely to hurt us. That’s why we proposed a fix to the fundamental way decisions are made by the City.

There’s a long list of poor decisions created by this opaqueness that shows how this has cost the City tens of millions of dollars. He points out symptoms of a much deeper problem that is impeding us from developing a long term vision.

It may seem like so much “inside baseball” to focus on the nuts and bolts of process, but its that process that is at the root of the crisis, as boring as that may seem. 

 

CAISO doesn’t quite grasp what led to rolling blackouts

Steve Berberich, CEO of the California Independent System Operator, assessed for GTM  his views on the reasons for the rolling blackouts in the face of a record setting heat wave. He overlooked a key reason for the delay on capacity procurement (called “resource adequacy” or RA) and he demonstrated a lack of understanding of how renewables and batteries will integrate to provide peak capacity.

Berberich is unwilling to acknowledge that at least part of the RA procurement problem was created by CAISO’s unwillingness to step in as a residual buyer in the RA market, which then created resistance by the CCAs to putting the IOUs in that role. RA procurement was delayed at least a year due to CAISO’s reluctance. CAISO appears to be politically tone-deaf to the issues being raised by CCAs on system procurement.

He says that solar will have to be overbuilt to supply energy to batteries for peak load. But that is already the case with the NQC ELCC just a fraction of the installed solar and wind capacity. Renewable capacity above the ELCC is available to charge the batteries for later use. The only question then is how much energy is required from the batteries to support the peak load and is that coming from existing renewables fleet. The resource adequacy paradigm has changed (more akin to the old PNW hydro system) in which energy, not built capacity is becoming the constraint.

Levelized costs are calculated correctly

The Utility Dive recently published an opinion article that claimed that the conventional method of calculating the levelized cost of energy (LCOE) is incorrect. The UD article was derived from an article published in 2019 in the Electricity Journal by the same author, James Loewen. The article claimed that conventional method gave biased results against more capital intensive generation resources such as renewables compared to fossil fueled ones. I wrote a comment to the Electricity Journal showing the errors in Loewen’s reasoning and further reinforcing the rationale for the conventional LCOE calculation. (You have until August 9 to download my article for free.)

I was the managing consultant that assisted the California Energy Commission (CEC) in preparing one of the studies (CEC 2015) referenced in Loewen. I also led the preparation of three earlier studies that updated cost estimates. (CEC 2003, CEC 2007, CEC 2010) In developing these models, the consultants and staff discussed extensively this issue and came to the conclusion that the LCOE must be calculated by discounting both future cashflows and future energy production. Only in this way can a true comparison of discounted energy values be made.

The error in Loewen’s article arises from a misconception that money is somehow different and unique from all other goods and services. Money serves three roles in the economy: as a medium of exchange, as a unit of account, and as a store of value. At its core, money is a commodity used predominantly as an intermediary in the barter economy and as a store of value until needed later. (We can see this particularly when currency was generally backed by a specific commodity–gold.) Discounting derives from the opportunity cost of holding, and not using, that value until a future date. So discounting applies to all resources and services, not just to money.

Blanchard and Fischer (1989) at pp. 70-71, describe how “utility” (which is NOT measured in money) is discounted in economic analysis. Utility is gained by consumption of goods and services. Blanchard and Fischer has an extensive discussion of the marginal rate of substitution between two periods. Again, note there is no discussion of money in this economic analysis–only the consumption of goods and services in two different time periods. That means that goods and services are being discounted directly. The LCOE must be calculated in the same manner to be consistent with economic theory.

We should be able to recover the net present value of project cost by multiplying the LCOE by the generation over the economic life of the project. We only get the correct answer if we use the conventional LCOE.  I walk through the calculation demonstrating this result in the article.

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.

Profound proposals in SCE’s rate case

A catastrophic crisis calls for radical solutions that are considered out of the box. This includes asking utility shareholders to share in the the same pain as their customers.

M.Cubed is testifying on Southern California Edison’s 2021 General Rate Case (GRC) on behalf of the Small Business Utility Advocates. Small businesses represent nearly half of California’s economy. A recent survey shows that more than 40% of such firms are closed or will close in the near future. While these businesses struggle, the utilities currently assured a steady income, and SCE is asking for a 20% revenue requirement increase on top already high rates.

In this context, SBUA filed M.Cubed’s testimony on May 5 recommending that the California Public Utilities Commission take the following actions in response to SCE’s application related to commercial customers:

  • Order SCE to withdraw its present application and refile it with updated forecasts (that were filed last August) and assumptions that better fit the changed circumstances caused by the ongoing Covid-19 crisis.
  • Request that California issue a Rate Revenue Reduction bond that can be used to reduce SCE’s rates by 10%. The state did this in 1996 in anticipation of restructuring, and again in 2001 after the energy crisis.
  • Freeze all but essential utility investment. Much of SCE’s proposed increase is for “load growth” that has not materialized in the past, and even less likely now.
  • Require shareholders, rather than ratepayers, to bear the risks of underutilized or cost-ineffective investments.
  • Reduce Edison’s authorized rate-of-return by an amount proportionate to its lower sales until load levels and characteristics return to 2019 levels or demonstrably reach local demand levels at the circuit or substation that justify requested investment as “used and useful.”
  • Enact Covid-19 Commercial Class Economic Develop (ED) and Supply Chain Repatriation rates. These rates should be at least partially funded in part by SCE shareholders.
  • Order Edison to prioritize deployment of beneficial, flexible, distributed energy resources (DER) in-lieu of fixed distribution investments within its grid modernization program. SCE should not be throwing up barriers to this transformation.
  • Order Edison to reconcile its load forecasts for its local “adjustments” with its overall system forecast to avoid systemic over-forecasting, which leads to investment in excess distribution capacity.
  • Order SCE to revise and refile its distribution investment plan to align its load growth planning with the CPUC-adopted load forecasts for resource planning and to shift more funds to the grid modernization functions that focus on facilitating DER deployment specified in SCE’s application.
  • Order an audit of SCE’s spending in other categories to determine if the activities are justified and appropriate cost controls are in place.  A comparison of authorized and actual 2019 capital expenditures found divergences as large as 65% from forecasted spending. The pattern shows that SCE appears to just spend up to its total authorized amount and then justify its spending after the fact.

M.Cubed goes into greater depth on the rationale for each of these recommendations. The CPUC does not offer many forums for these types of proposals, so SBUA has taken the opportunity offered by SCE’s overall revenue requirement request to plunge in.

(image: Steve Cicala, U. of Chicago)

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.

How to choose a water system model

The California Water & Environmental Modeling Forum (CWEMF) has proposed to update its water modeling protocol guidance, last issued in 2000. This modeling protocol applies to many other settings, including electricity production and planning (which I am familiar with). I led the review of electricity system simulation models for the California Energy Commission, and asked many of these questions then.

Questions that should be addressed in water system modeling include:

  • Models can be used for either short-term operational or long term planning purposes—models rarely can serve both masters. The model should be chosen for its analytic focus is on predicting with accuracy and/or precision a particular outcome (usually for short term operations) or identifying resilience and sustainability.
  • There can be a trade off between accuracy and precision. And focusing overly so on precision in one aspect of a model is unlikely to improve the overall accuracy of the model due to the lack of precision elsewhere. In addition, increased precision also increases processing time, thus slowing output and flexibility.
  • A model should be able to produce multiple outcomes quickly as a “scenario generator” for analyzing uncertainty, risk and vulnerability. The model should be tested for accuracy when relaxing key constraints that increase processing time. For example, in an electricity production model, relaxing the unit commitment algorithm increased processing speed twelve fold while losing only 7 percent in accuracy, mostly in the extreme tail cases.
  • Water models should be able to use different water condition sequences rather than relying on historic traces. In the latter case, models may operate as though the future is known with certainty.
  • Water management models should include the full set of opportunity costs for water supply, power generation, flood protection and groundwater pumping. This implies that some type of linkage should exist between these types of models.