Tag Archives: investor-owned utilities

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)

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?

 

 

 

 

Utilities’ returns are too high (Part 2)

IOU ROE premiums

My previous post, Part 1, showed how California’s utilities’ share prices have risen well above the average across utilities despite claims that investors are risk averse to the California utilities. That valuation premium reflects an excessively high authorized return on equity (ROE) from the California Public Utilities Commission (CPUC).

The utilities’ market values can then be linked to the utilities’ book values and authorized returns on equity to calculate the implied market returns on equity. The authorized income per share is the authorized ROE multiplied by the book value per share. That income is divided by the market share price to arrive at the implied market return on equity for that company. Both Sempra (SRE) and Edison International (EIX) significantly outperform the Dow Jones Utility average and PG&E Corporation (PGC) maintained the same trend until market had significant concerns about the company’s role in the 2017 wildfires.

The figure above tracks the difference or premium value of the authorized ROE over the market valuation of that ROE. A premium value of zero means that the market valuation is on par with the authorized ROE. A higher or positive premium value means that investors see the utility’s equity shares as attractive investments with lower risks than the assessments of the commissions that set the authorized ROEs. In other words, a commission is providing an overly generous incentive to investors if the premium value is positive.  The figure above compares the market implied ROE for the three California holding companies to a market basket of 10 U.S. holding companies that own 17 electric and gas utilities, and do not own significant non-utility subsidiaries. 

At the time of the 2012 cost of capital decision, the authorized ROEs for the California utilities and the basket of U.S. utilities were close to the implied market ROEs. Except for Sempra, which was an outlier as evidenced by its share price growth relative to the other utilities, the authorized ROE was within 100 basis points of the implied market ROE at the end of 2012.  For both Edison International and PG&E Corporation, the authorized ROE and the implied market ROE on December 31, 2012 were exactly on par—10.5% for Edison and 10.4% for PG&E. Only Sempra showed a positive premium of 300 basis points as a result of a rapid increase in market value over 2012.

Over the period from 2012 to late 2017, the implied market ROEprogressed steadily downward–that is, the market value premium increased–for both the California utilities and the other U.S. utilities. Sempra’s premium leveled off in late 2014 and has drifted downward since without any significant corrections. SCE’s diverged upward some from the U.S. utilities mid-2016, but again there are not sharp changes in direction, even with the Thomas Fire in late 2017. PG&E followed the same pattern as SCE until the Wine Country fires in late 2017, and took another sharp turn with the Camp Fire and, understandably, the subsequent voluntary bankruptcy filing.

We can see at the end of September 2017, just after the last Commission decision on cost of capital, the market premium for the 10 utilities had grown to 470 basis points. The premiums for PG&E, Edison and Sempra all lied in a narrow band between 410 basis points for Edison and 470 basis points for PG&E. In other words, 1) California utility investors were receiving overly generous returns on their investments as evidenced in the share prices, and 2) California utility investors have not been demanding a significant discount for perceived increased risk compared to other U.S. utilities, contrary to the assertions by the utilities’ witnesses in this proceeding.

 

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.