Tag Archives: SCE

Utilities’ returns are too high (Part 2)

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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)

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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

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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.

PG&E has cost California over $3 billion by mismanaging its RPS portfolio

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CCA Savings

When community choice aggregators take up serving PG&E customers, PG&E saves the cost of having to procure power for the departed load. Instead the CCAs bear that cost for that power. The savings to PG&E’s bundled customers are not fully reflected when calculating the exit fee (known as the power charge indifference adjustment or PCIA) for those CCAs. As a result, the exit fee does not reflect the true value that CCAs provide to PG&E and its bundled customers.

The chart above shows the realized and potential savings to PG&E from the departure of CCA customers. The realized part is the avoided costs of procuring resources to meet that load, shown in yellow. The second part is the foregone sales opportunity if PG&E had sold a portion of its portfolio to the CCAs at the going price when they departed. In 2019, these combined savings could have reached $3.2 billion if PG&E had acted prudently.

Many local governments launched CCAs to address their climate goals, and CCAs issued multiple requests for offers of RPS energy.  However, PG&E failed to respond to this opportunity to sell excess renewable energy no longer needed to serve their customers.  By deciding to hold these unneeded resources in a declining market, PG&E accumulated additional losses every year.  Indeed, the assigned Judge on the exit-fee proceeding at the CPUC concluded that PG&E must benefit from “holding back the RECs [renewable energy credits] for some reason.”

This willingness to hold onto an unneeded resource that loses value every year is contrary to prudent management.  However, shareholders, are shielded entirely from contract that are too costly, and only pay penalties for failing to meet RPS targets.  Instead, ratepayers—both bundled and CCA—pay all of the excessive costs, and shareholders only have a strong incentive to over-procure using those ratepayer dollars to avoid any possibility of reduced shareholder profits.  Holding these contracts also inflates the exit-fee departed customers must pay, making it harder for alternatives like public power and distributed generation to PG&E to thrive.

When Sonoma Clean Power launched in 2014, the average price of RPS energy was $128/MWh.  It has declined every year, and now sits at $57/MWh.  PG&E’s decision to not sell excess energy at 2014 prices, and to protect shareholders at the expense of ratepayers has cost customers over $3 billion dollars in the last 6 years as shown in the green columns below.  As RPS prices continue to decline, and the amount of customer departing increases, this figure will continue to increase every year.  Indeed, it surpassed $1.1 billion for 2019 alone.

PGAE Mismanagement Costs

Further, the hedging value of the RPS resources that PG&E listed as key attribute of holding these PPAs instead of disposing of them has diminished dramatically since PG&E pushed that as its strategy in its 2014 Bundled Procurement Plan. As shown in the chart above, the hedge value fell $1.3 billion from 2014 to 2019, from a high of $961 million to a burden of $343 million. PG&E’s hedge now adds $33/MWH to the cost of its renewables portfolio.

In comparison, Southern California Edison’s renewables portfolio costs just under $20/MWH less than PG&E’s. SCE did not rush into signing PPAs like PG&E and did not sign them for as long of terms as PG&E.

 

A counter to UC’s skepticism about CCAs

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Kevin Novan from UC Davis wrote an article in the University of California Giannini Foundation’s Agriculture and Resource Economics Update entitled “Should Communities Get into the Power Marketing Business?” Novan was skeptical of the gains from community choice aggregation (CCA), concluding that continued centrally planned procurement was preferable. Other UC-affiliated energy economists have also expressed skepticism, including Catherine Wolfram, Severin Borenstein, and Maximilian Auffhammer.

At the heart of this issue is the question of whether the gains of “perfect” coordination outweigh the losses from rent-seeking and increased risks from centralized decision making. I don’t consider myself an Austrian economist, but I’m becoming a fan of the principle that the overall outcomes of many decentralized decisions is likely to be better than a single “all eggs in one basket” decision. We pretend that the “central” planner is somehow omniscient and prudently minimizes risks. But after three decades of regulatory practice, I see that the regulators are not particularly competent at choosing the best course of action and have difficulty understanding key concepts in risk mitigation.By distributing decision making, we better capture a range of risk tolerances and bring more information to the market place. There are further social gains from dispersed political decision making that brings accountability much closer to home and increases transparency. Of course, there’s a limit on how far decentralization should go–each household can’t effectively negotiate separate power contracts. But we gain much more information by adding a number of generation service providers or “load serving entities” (LSE) to the market.

I found several shortcomings with with Novan’s article that would change the tenor. I take each in turn:

  • He wrote “it remains to be seen whether local governments will make prudent decisions…” However, he did not provide the background which explains at least in part why the CCAs have arisen in the first place. Largely over the last 40 years, the utilities have made imprudent procurement and planning decisions. Whether those have been pushed on the utilities by the CPUC and Legislature or whether the IOUs have some responsibility, the fact is that neither institution sees real consequences for these decisions, neither financially or politically. In fact, the one time that a CPUC commissioner attempted to deliver consequences to the IOUs, she was fired and replaced by a former utility CEO. The appropriate comparison for local government decision making is to the current baseline record, not an academic hypothetical that will never exist. And by the way, government enterprise agencies, including municipal utilities, have a relatively good record as demonstrated as by lower electricity rates and relatively well managed, almost invisible capital intensive water and sanitation utilities. The current CCAs have a more extensive portfolio risk management system than PG&E—my calculation of PG&E’s implicit risk hedge in its renewables portfolio is an astounding 3.3 cents per kilowatt-hour.
  • Novan complains that CCAs have “dual objectives.” In fact they have “triple objectives,” the added one to encourage local economic development (sometimes through lower rates). I suggest reading the mission statements of the CCAs that have been created, including the local Valley Clean Energy Authority .
  • It’s not clear that “purchasing locally produced renewable energy will likely lead to more expensive renewable output” for at least two reasons. The first is that local power can avoid further transmission investment. The current CAISO transmission access charges range from $11 to $39 per megawatt-hour and is forecasted to continue to rise significantly (indicating transmission marginal costs are much above average costs). In a commentary on a UC Energy Institute blog, it was revealed that the Sunrise line may have cost as much as $80 per MWH for power from the desert. This wipes out much of the difference between utility scale and DG solar power. Building locally avoids yet more expensive transmission investment to the southeast desert. [I worked on the DRECP for the CEC.] In addition, local power can avoid distribution investment and will be reflected in the IOU’s distribution resource plans (DRP). And second, the scale economies for solar PV plants largely disappears after about 10 MW. So larger plants don’t necessarily mean cheaper, (especially if they have to implement more extensive environmental mitigation.) [I prepared the Cost of Generation model and report for the CEC from 2001-2013.]
  • It’s not necessary that more renewable capacity is needed for local generation. The average line losses in the CAISO system are about 6%, and those are greater from the far desert region. Whether increased productivity overcomes that difference is an empirical question that I haven’t seen answered satisfactorily yet.
  • Novan left unstated his premise defining “greener” renewables, but I presume that it’s based almost entirely on GHG emissions. However, local power is likely “greener” because it avoids other environmental impacts as well. Local renewables are much more likely to be built on brownfields and even rooftops so there’s not added footprints. In contrast there is growing opposition to new plants in the desert region. The second advantage is the avoidance of added transmission corridors. One only needs to look at the Sunrise and Tehachipi lines to see how those consequences can slow down the process. Local DG can avoid distribution investment that has consequences as well. Further, local power provides local system support that can displace local natural gas generation. In fact, one of the key issues for Southern California is the need to maintain in-basin generation to support imports of renewables across the LA Basin interface. [I assessed the need for local generation in the LA Basin in the face of various environmental regulations for the CEC.]

I was on the City of Davis Community Choice Energy Advisory Committee, and I am testifying on behalf of the California CCAs on the setting of the PCIA in several dockets. I have a Ph.D. from Berkeley’s ARE program and have worked on energy, environmental and water issues for about 30 years.

 

 

 

 

CCAs add renewables while utilities stand pat

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California’s community choice aggegrators (CCAs) are on track to meet their state-mandated renewable portfolio standard obligations. PG&E, SCE and SDG&E have not signed significant new renewable power capacity since 2015, while CCAs have been building new projects. To achieve zero carbon electricity by 2050 will require aggressive plans to procure new renewables soon.

CCAs reach RPS targets with long-term PPAs

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Joint CCA Notice of Ex Parte 10.24.16_CCS-RPS

As I listen to the opening of the joint California Customer Choice En Banc held by the CPUC and CEC, I hear Commissioners and speakers claiming that community choice aggregators (CCAs) are taking advantage of the current market and shirking their responsibilities for developing a responsible, resilient resource portfolio.

The CPUC’s view has two problems. The first is an unreasonable expectation that CCAs can start immediately as a full-grown organization with a complete procurement organization, and more importantly, a rock solid credit history. The second is how the CPUC has ignored the fact that the CCAs have already surpassed the state’s RPS targets  in most cases and that they have significant shares of long-term power purchase agreements (PPAs).

State law in fact penalizes excess procurement of RPS-eligible power by requiring that 65% of that specific portfolio be locked into long-term PPAs, regardless of the prudency of that policy. PG&E has already demonstrated that they have been unable to prudently manage its long-term portfolio, incurring a 3.3 cents per kilowatt-hour risk hedge premium on its RPS portfolio. (Admittedly, that provision could be interpreted to be 65% of the RPS target, e.g., 21.5% of a portfolio that has met the 33% RPS target, but that is not clear from the statute.)

 

Why the CPUC has it wrong on the PCIA

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Nick Chaset is the CEO of East Bay Community Energy which is a community choice aggregator (CCA) that serves Alameda County. He also was Commission President Michael Picker’s chief advisor until last year when he left for EBCE. He explains in this article how two proposed decisions that the CPUC is considering are fundamentally wrong and will shift cost onto CCA customers. (I testified on behalf of CalCCA in this proceeding. I’ll have more on this before the Commission’s scheduled vote October 11.)

Figure 1 – CPUC’s Proposed Resource Adequacy Value vs. True Market Values

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Figure 2 – GHG Premium Value Missing from CPUC Proposed Decision

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Figure 3 – Falling Utility Rates as Customers Depart Filed in Their ERRA Rate Applications

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Another bad legislative idea: Pushing RPS purchase

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The California Legislature is considering a bill (AB 893) that would require the state’s regulated utilities (including CCAs as well as investor-owned) to buy at least 4,250 megawatts of renewables before federal tax credits expire in 2022.

Unfortunately, this will not create the cost savings that seem so obvious. This argument was made by the renewable energy plant owners in the Diablo Canyon Power Plant retirement case (A.16-08-006) and rejected by the CPUC in its decision. While the tax credits lower current costs, these are more than offset by waiting for technology costs to fall even further, as shown by the solar power forecast above. Combined with the time value of money (discounting), the value of waiting far outweighs prematurely buying renewables.

The legislature already passed a bill (SB 1090) that requires the CPUC to ensure that GHG emissions will not rise when Diablo Canyon retires in 2024 and 2025 when approving integrated resource plans. (Whether the governor signs this overly directive law is another question.) And SB 100 requires reaching 100% carbon free by 2045. A study just released by the Energy Institute at Haas indicates that renewables to date have depressed energy market prices, discouraging further investment. And the CAISO is “managing oversupply” created by the current renewable generation.

And there’s a further problem–with a large number of customers moving from the IOUs to CCAs across all three utilities, the question is “who should be responsible for buying this power?” The CCAs will have their own preferences (often locally and community-scale) that will conflict with any choices made by the IOUs. The CCAs are already saddled with poor procurement and portfolio management decisions by the IOUs through exit fees. (PG&E has an embedded risk premium of $33 per megawatt-hour in its RPS portfolio costs.) Why would we want the IOUs to continue to mismanage our power resources?