Tag Archives: CPUC

AB1139 would undermine California’s efforts on climate change

Assembly Bill 1139 is offered as a supposed solution to unaffordable electricity rates for Californians. Unfortunately, the bill would undermine the state’s efforts to reduce greenhouse gas emissions by crippling several key initiatives that rely on wider deployment of rooftop solar and other distributed energy resources.

  • It will make complying with the Title 24 building code requiring solar panel on new houses prohibitively expensive. The new code pushes new houses to net zero electricity usage. AB 1139 would create a conflict with existing state laws and regulations.
  • The state’s initiative to increase housing and improve affordability will be dealt a blow if new homeowners have to pay for panels that won’t save them money.
  • It will make transportation electrification and the Governor’s executive order aiming for 100% new EVs by 2035 much more expensive because it will make it much less economic to use EVs for grid charging and will reduce the amount of direct solar panel charging.
  • Rooftop solar was installed as a long-term resource based on a contractual commitment by the utilities to maintain pricing terms for at least the life of the panels. Undermining that investment will undermine the incentive for consumers to participate in any state-directed conservation program to reduce energy or water use.

If the State Legislature wants to reduce ratepayer costs by revising contractual agreements, the more direct solution is to direct renegotiation of RPS PPAs. For PG&E, these contracts represent more than $1 billion a year in excess costs, which dwarfs any of the actual, if any, subsidies to NEM customers. The fact is that solar rooftops displaced the very expensive renewables that the IOUs signed, and probably led to a cancellation of auctions around 2015 that would have just further encumbered us.

The bill would force net energy metered (NEM) customers to pay twice for their power, once for the solar panels and again for the poor portfolio management decisions by the utilities. The utilities claim that $3 billion is being transferred from customers without solar to NEM customers. In SDG&E’s service territory, the claim is that the subsidy costs other ratepayers $230 per year, which translates to $1,438 per year for each NEM customer. But based on an average usage of 500 kWh per month, that implies each NEM customer is receiving a subsidy of $0.24/kWh compared to an average rate of $0.27 per kWh. In simple terms, SDG&E is claiming that rooftop solar saves almost nothing in avoided energy purchases and system investment. This contrasts with the presumption that energy efficiency improvements save utilities in avoided energy purchases and system investments. The math only works if one agrees with the utilities’ premise that they are entitled to sell power to serve an entire customer’s demand–in other words, solar rooftops shouldn’t exist.

Finally, this initiative would squash a key motivator that has driven enthusiasm in the public for growing environmental awareness. The message from the state would be that we can only rely on corporate America to solve our climate problems and that we can no longer take individual responsibility. That may be the biggest threat to achieving our climate management goals.

What is driving California’s high electricity prices?

This report by Next10 and the University of California Energy Institute was prepared for the CPUC’s en banc hearing February 24. The report compares average electricity rates against other states, and against an estimate of “marginal costs”. (The latter estimate is too low but appears to rely mostly on the E3 Avoided Cost Calculator.) It shows those rates to be multiples of the marginal costs. (PG&E’s General Rate Case workpapers calculates that its rates are about double the marginal costs estimated in that proceeding.) The study attempts to list the reasons why the authors think these rates are too high, but it misses the real drivers on these rate increases. It also uses an incorrect method for calculating the market value of acquisitions and deferred investments, using the current market value instead of the value at the time that the decisions were made.

We can explore the reasons why PG&E’s rates are so high, much of which is applicable to the other two utilities as well. Starting with generation costs, PG&E’s portfolio mismanagement is not explained away with a simple assertion that the utility bought when prices were higher. In fact, PG&E failed in several ways.

First, PG&E knew about the risk of customer exit as early as 2010 as revealed during the PCIA rulemaking hearings in 2018. PG&E continued to procure as though it would be serving its entire service area instead of planning for the rise of CCAs. Further PG&E also was told as early as 2010 (in my GRC testimony) that it was consistently forecasting too high, but it didn’t bother to correct thee error. Instead, service area load is basically at the save level that it was a decade ago.

Second, PG&E could have procured in stages rather than in two large rounds of request for offers (RFOs) which it finished by 2013. By 2011 PG&E should have realized that solar costs were dropping quickly (if they had read the CEC Cost of Generation Report that I managed) and that it should have rolled out the RFOs in a manner to take advantage of that improvement. Further, they could have signed PPAs for the minimum period under state law of 10 years rather than the industry standard 30 years. PG&E was managing its portfolio in the standard practice manner which was foolish in the face of what was occurring.

Third, PG&E failed to offer part of its portfolio for sale to CCAs as they departed until 2018. Instead, PG&E could have unloaded its expensive portfolio in stages starting in 2010. The ease of the recent RPS sales illustrates that PG&E’s claims about creditworthiness and other problems had no foundation.

I calculated the what the cost of PG&E’s mismanagement has been here. While SCE and SDG&E have not faced the same degree of exit by CCAs, the same basic problems exist in their portfolios.

Another factor for PG&E is the fact that ratepayers have paid twice for Diablo Canyon. I explain here how PG&E fully recovered its initial investment costs by 1998, but as part of restructuring got to roll most of its costs back into rates. Fortunately these units retire by 2025 and rates will go down substantially as a result.

In distribution costs, both PG&E and SCE requested over $2 billion for “new growth” in each of its GRCs since 2009, despite my testimony showing that growth was not going to materialize, and did not materialize. If the growth was arising from the addition of new developments, the developers and new customers should have been paying for those additions through the line extension rules that assign that cost responsibility. The utilities’ distribution planning process is opaque. When asked for the workpapers underlying the planning process, both PG&E and SCE responded that the entirety were contained in the Word tables in each of their testimonies. The growth projections had not been reconciled with the system load forecasts until this latest GRC, so the totals of the individual planning units exceeded the projected total system growth (which was too high as well when compared to both other internal growth projections and realized growth). The result is a gross overinvestment in distribution infrastructure with substantial overcapacity in many places.

For transmission, the true incremental cost has not been fully reported which means that other cost-effective solutions, including smaller and closer renewables, have been ignored. Transmission rates have more than doubled over the last decade as a result.

The Next10 report does not appear to reflect the full value of public purpose program spending on energy efficiency, in large part because it uses a short-run estimate of marginal costs. The report similarly underestimates the value of behind-the-meter solar rooftops as well. The correct method for both is to use the market value of deferred resources–generation, transmission and distribution–when those resources were added. So for example, a solar rooftop installed in 2013 was displacing utility scale renewables that cost more than $100 per megawatt-hour. These should not be compared to the current market value of less than $60 per megawatt-hour because that investment was not made on a speculative basis–it was a contract based on embedded utility costs.

The PCIA is heading California toward another energy crisis

The California ISO Department of Market Monitoring notes in its comments to the CPUC on proposals to address resource adequacy shortages during last August’s rolling blackouts that the number of fixed price contracts are decreasing. In DMM’s opinion, this leaves California’s market exposed to the potential for greater market manipulation. The diminishing tolling agreements and longer term contracts DMM observes is the result of the structure of the power cost indifference adjustment (PCIA) or “exit fee” for departed community choice aggregation (CCA) and direct access (DA) customers. The IOUs are left shedding contracts as their loads fall.

The PCIA is pegged to short run market prices (even more so with the true up feature added in 2019.) The PCIA mechanism works as a price hedge against the short term market values for assets for CCAs and suppresses the incentives for long-term contracts. This discourages CCAs from signing long-term agreements with renewables.

The PCIA acts as an almost perfect hedge on the retail price for departed load customers because an increase in the CAISO and capacity market prices lead to a commensurate decrease in the PCIA, so the overall retail rate remains the same regardless of where the market moves. The IOUs are all so long on their resources, that market price variation has a relatively small impact on their overall rates.

This situation is almost identical to the relationship of the competition transition charge (CTC) implemented during restructuring starting in 1998. Again, energy service providers (ESPs) have little incentive to hedge their portfolios because the CTC was tied directly to the CAISO/PX prices, so the CTC moved inversely with market prices. Only when the CAISO prices exceeded the average cost of the IOUs’ portfolios did the high prices become a problem for ESPs and their customers.

As in 1998, the solution is to have a fixed, upfront exit fee paid by departing customers that is not tied to variations in future market prices. (Commissioner Jesse Knight’s proposal along this line was rejected by the other commissioners.) By doing so, load serving entities (LSEs) will be left to hedging their own portfolios on their own basis. That will lead to LSEs signing more long term agreements of various kinds.

The alternative of forcing CCAs and ESP to sign fixed price contracts under the current PCIA structure forces them to bear the risk burden of both departed and bundled customers, and the IOUs are able to pass through the risks of their long term agreements through the PCIA.

California would be well service by the DMM to point out this inherent structural problem. We should learn from our previous errors.

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)

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.

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.

End the fiction of regulatory oversight of California’s generation

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M.Cubed is the only firm willing to sign the non-disclosure agreements (NDA) that allow us to review the investor-owned utilities’ (IOUs) generation portfolio data on behalf of outside intervenors, such as the community choice aggregators (CCAs). Even the direct access (DA) customers who constitute about a quarter of California’s industrial load are represented by a firm that is unwilling to sign the NDAs. This situation places departed load customers, and in fact all customers, at a distinct disadvantage when trying to regulate the actions of the IOUs. It is simply impossible for a single small firm to scrutinize all of the filings and data from the IOUs. (Not to mention that one, SDG&E, gets a complete free pass for now as that it has no CCAs.)

This situation has arisen because the NDAs require that the “reviewing representatives” not be in a position to advise market participants, such as CCAs or energy service providers (ESPs) that sell to DA customers, on procurement decisions. This is an outgrowth of AB 57 in 2002, a state law passed to bring IOUs back into the generation market after the collapse of restructuring in 2001. That law was intended to the balance of power to the IOUs away from generators for procurement purposes. Now it puts the IOUs at a competitive advantage against other load serving entities (LSEs) such as CCAs and ESPs, and even bundled customers.

This imbalance has arisen for several insurmountable reasons:

  • No firm can build its business on serving only to review IOU filings without offering other procurement consulting services to clients.
  • It is difficult to build expertise for reviewing IOU filings without participating in procurement services for other LSEs or resource providers. (I am uniquely situated by the consulting work I did for the CEC on assessing generation technology costs for over a decade.)
  • CPUC staff similarly lacks the expertise for many of the same reasons, and are relatively ineffective at these reviews. The CPUC is further limited by its ability to recruit sufficient qualified staff for a variety of reasons.

If California wants to rein in the misbehavior by IOUs (such as what I’ve documented on past procurement and shareholder returns earlier), then we have two options to address this problem going forward:

  1. Transform at least the power generation management side of the IOUs into publicly owned entities with more transparent management review.
  2. End the annual review and setting of PCIA and CTC rates by establishing one-time prepayment amounts. By prepaying or setting a fixed annual amount, the impact of accounting maneuvers are diminished substantially, and since IOUs can no longer shift portfolio management risks to departed load customers, the IOUs more directly face the competitive pressures that should make them more efficient managers.

Utilities’ returns are too high (Part 1)

IOU share prices

An analysis of equity market activity indicates that investors have not priced a risk discount into California utility shares, and instead, until the recent wildfires, utility investors have placed a premium value on California utility stocks. This premium value indicates that investors have viewed California as either less risky than other states’ utilities or that California has provided a more lucrative return on investment than other states.

The California Public Utilities Commission (CPUC) should set the authorized return on equity to shareholders (ROE) to deliver an after-tax net income amount as a percentage of the capital invested by the utility or the “book value.” As Alfred Kahn wrote, “the sharp appreciation in the prices of public utility stocks, to one and half and then two times their book values during this period [the 1960s] reflected also a growing recognition that the companies in question were in fact being permitted to earn considerably more than their cost of capital.” (see footnote 69)

The book value is fairly stable and tends to grow over time as higher cost capital is invested to meet growth and to replace older, lower cost equipment. Investors use this forecasted income to determine their valuation of the company’s common stock in market transactions. Generally the accepted valuation is the net present value of the income stream using a discount rate equal to the expected return on that investment. That expected return represents the market-based return on equity or the implied market return.

Alfred Kahn wrote that a commission should generally target the ROE so that the book and market values of the utility company are roughly comparable. In that way, when the utility adds capital, that capital receives a return that closely matches the return investors expect in the market place. If the regulated ROE is low relative to the market ROE, the company will have difficulty raising sufficient capital from the market for needed investments. If the regulated ROE is high relative to the market ROE, ratepayers will pay too much for capital invested and excess economic resources will be diverted into the utility’s costs. On this premise, we compared each of the utilities’ market valuation and implied market ROE against market baskets of U.S. utilities and the current authorized ROEs.

The figure above shows how the stock price for each of the three California utility holding companies (PG&E Corporation (ticker symbol PCG), Edison International (EIX) and Sempra (SRE)) that own the four large California energy utilities. The figure compares these stock prices to the Dow Jones Utility index average from June 1998 to July 2019 starting from a common base index value of 100 on January 1, 2000. The chart also includes (a) important Commission decisions and state laws that have been enacted and are identified by several of the utility witnesses as increasing the legal and regulatory risk environment in the state, and (b) catastrophic events at particular utilities that could affect how investors perceive the risk and management of that utility.

Table 1 summarizes the annual average growth in share prices for the Dow Jones Utility average and the three holding companies up to the 2012 cost of capital decision, the 2017 cost of capital modification decision, and to July 2019. Also of particular note, the chart includes the Commission’s decision on incorporating a risk-based framework into each utility’s General Rate Case process in D.14-12-025. The significance of this decision is that the utility’s consideration of safety risk was directed to be “baked in” to future requests for new capital investment. The updated risk framework also has the impact of making new these new investments more secure from an investment perspective, since there is closer financial monitoring and tracking.

As you can see in both Table 1 and in the figure, the Dow Jones Utility average annual growth was 5.5% through July 13, 2017 and 5.8% through July 18, 2019, California utility prices exceeded this average in all but one case, with Edison’s shares rising 9.4% per annum through the first date and 8.4% through this July, and Sempra growing 15.2% to the first date and even more at 15.3% to the latest. Even PG&E grew at almost twice the index rate at 10.4% in 2017, and then took an expected sharp decline with its bankruptcy.

Table 1

Cumulative Average Growth from January 2000 12/12/2012 7/13/2017 7/18/2019
Dow Jones Utilities 3.9% 5.5% 5.8%
Edison International 7.2% 9.4% 8.4%
PG&E Corp. 8.6% 10.4% 2.4%
Sempra 15.8% 15.2% 15.3%

The chart and table support three important findings:

  • California utility shares have significantly outpaced industry average returns since January 2000 and since March 2009;
  • California share prices only decreased significantly after the wildfire events that have been tied to specific market-perceived negligence on the part of the electric utilities in 2017 and 2018; and
  • Other events and state policy actions do not appear to have a measurable sustained impact on utilities’ valuations.

In Part 2, I show how utilities’ premiums on their authorized ROE have grown over the last decade.

Exit fee market benchmarks threaten CCAs abilities to meet long term obligations

Capacity Net Revenue Adequacy 2001-2018CCAs may have to choose between complying with the long-term commitments specified in Senate Bill 350 and continuing to operate because they cannot acquire resources at the specified market price benchmarks that value the entire utility portfolio according to the CPUC.

The chart above compares the revenue shortfalls that need to be made up from other capacity sales products to finance resource additions. The CAISO has reported for every year since 2001 that its short-run market clearing prices that were adopted as the market price benchmark in the PCIA have been insufficient to support new conventional generation investment. The chart above shows the results of the CAISO Annual Report on Market Issues and Performance compiled from 2012 to 2018, separated by north (NP15 RRQ) and south (SP15 RRQ) revenue requirements for new resources. (The historic data shows that CAISO revenues have never been sufficient to finance a resource addition.) The CAISO signs capacity procurement (CPM) agreements to meet near-term reliability shortfalls which is one revenue source for a limited number of generators. The other short run price is the resource adequacy credits transacted by load serving entities (LSE) such as the utilities and CCAs. This revenue source is available to a broader set of resources. However, neither of revenues come close to closing the cost shortfall for new capacity.

The CPUC and the CAISO have deliberately suppressed these market prices to avoid the price spikes and reliability problems that occurred during the 2000-2001 energy crisis. By explicit state policy, these market prices are not to be used for assessing resource acquisition benchmarks. Yet, the CPUC adopted in its PCIA OIR decision (D.18-10-019) exactly this stance by asserting that the CCAs must be able to acquire new resources at less than these prices to beat the benchmarks used to calculate the PCIA. The CPUC used the CAISO energy prices plus the average RA prices as the base for the market value benchmark that represents the CCA threshold.

In a functioning market, the relevant market prices should indicate the relative supply-demand balance–if supply is short then prices should rise sufficiently to cover the cost of new entrants. Based on the relative price balance in the chart, no new capacity resources should be needed for some time.

Yet the CPUC recently issued a decision (D.19-04-040) that ordered procurement of 2,000 MW of capacity for resource adequacy. And now the CPUC proposes to up that target to 4,000 MW by 2021. All of this runs counter to the price signals that CPUC claims represent the “market value” of the assets held by the utilities.

If the CCAs purchase resources that cost more than the PCIA benchmarks then they will be losing money for their ratepayers (note that CCAs have no shareholders). Most often long-term power purchase agreements (PPA) have prices above the short-term prices because those short-term prices do not cover all of the values transacted in the market place. (More on that in the near future.) The CPUC should either align its market value benchmarks with its resource acquisition directives or acknowledge that their directives are incorrect.