Tag Archives: PG&E

Non-Profit Utilities Could Cure What Ails California Electricity

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Severin Borenstein at the Energy Institute at Haas, asks “Would Non-Profit Utilities Cure What Ails California Electricity?” I am posting my response here as that I find his post overlooks several important points and distinctions.

I’ll start by saying I wrote an op-ed in the Sacramento Bee in the early 2000s noting that creating a new municipal utility was not going to deliver the same low rates as existing munis and I’m still aware that such a transfer is unlikely to reduce rates much. But it does change the governance structure in a way that is likely to be more accountable and less influenced by the private interests of utility shareholders. Communities are joining together to push for acquisition of PG&E by a cooperative, which would have a similar governance structure to a municipal utility.

First, the complaint about government is largely about agencies that I will call “ministerial” or “administrative”. These agencies issue permits and licenses or provide social services. In contrast, the government agencies that deliver utility services, which are “enterprises” largely deliver service with few complaints. About 80% of water utilities and almost all wastewater utilities are publicly owned. I work in the water arena as well, and the only utility that I hear complaints about from customers is LADWP (both water and power sides). (The SDCWA-MWD fight is between agencies’ managements, not from customers). On the other hand, all three or California’s electric IOUs are the target of customers’ ire. And the IOU staffs (which I have frequent contact with) are no better than government employees in their responsiveness or competence. One advantage the enterprise agencies have over the ministerial/administrative ones is that they generally pay a higher salary so employees are motivated in much the same way as those in the private sector. Moving from oversight by a ministerial/administrative agency (CPUC) to management by an enterprise utility should overcome the problem of recruiting competent motivated staff.

Second, shareholders shoulder very little risk now, particularly in California. I testified in the IOUs’ rate of return case and we asked for the amount of disallowances that shareholders had to bear over the last two decades. Other than SDG&E’s 2007 wildfire costs due to negligence on the utility’s part, they came pack with amounts that were in the tens of millions, which amounts to less than a 0.1% of their revenues collected over that period. Utilities’ generation investment is now so protected that the CPUC reversed itself last year and removed the 10 year recovery cap from exit fees for generation that the utilities built knowing the cap existed. They are now getting bonus dollars! (Same thing happened with Diablo Canyon in 1996.) Yet the utilities are claiming in that rate case that the return on equity should be increased even further! I have a blog post about how the current return is already too high. (Part 2 is the next day.)  Public ownership in contrast can reduce the return on capital from close to 10% (before tax) to 5% or less, which can cut rates substantially.

We can see how PG&E in particular has been incompetently managed for decades. I posted about its many foibles since the 1960s as well. The supposed incentives and efficiencies of the private sector have failed to materialize for California utilities, and meanwhile we pay higher costs for capital with no real risk mitigation. (Ratepayers still had to pay for PG&E’s debts after the 2000-01 energy crisis, and it looks like the same may happen again.)

Finally, the question arises as to whether municipalizing piecemeal would create inequities. The premise of the statement is that the current economic distribution is equitable. But the fact is that rural residential customers in the wildland/urban interface (WUI) have not been paying their full share of their costs and have been heavily subsidized by urban customers. Those customers in the WUI tend to be better off than average (poor rural customers are more likely to live in agricultural communities that are not subject to the same fire risks and for whom service costs are lower), so we already have an adverse wealth transfer in place. And those subsidies have facilitated expansion of housing into those high risk areas that also encourage longer commutes with more GHG emissions.

The better question is how can the rural service areas be better served in the future without relying on the traditional utility structure? Moving toward microgrids and other DER solutions to improve reliability while reducing fire risk is one solution. Spending a $100 billion on undergrounding lines to be paid for by everyone else is NOT a good solution.

Utilities’ returns are too high (Part 2)

IOU ROE premiums

Yesterday’s post 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.

The 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.

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.

Should California just buy PG&E?

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Governor Gavin Newsom asked Warren Buffet to use Berkshire-Hathaway to buy PG&E. Berkshire-Hathaway has been acquiring utilities throughout the West including PacifiCorp and Nevada Power. However, other than deep pockets, it’s not clear what Buffet has to offer in this situation.

PG&E’s stock fell as low as $3.80 per share on Tuesday, closing at $5.03. The total market value, including the natural gas utility, is now $2.66 billion. The invested book value on the other hand is about $26 billion.

Not sure why California doesn’t just buy the company for, say, $5B instead of appealing to an out of state private owner. Several state legislators, including a key state senator, Bill Dodd, have expressed support for some sort of state acquisition. Then the state can either parse it out to public utilities, set up a cooperative or bid out the franchises to multiple operators or owners. Ratepayers/taxpayers will have to pay most of the wildfire liabilities anyway, so why not remove the high-cost (and apparently incompetent) middleman?

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

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.

 

VCEA offers PG&E $300 million for Yolo County

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Valley Clean Energy Alliance made its official offer to PG&E to acquire the Yolo County distribution system for $300 million. The offer is being submitted in PG&E’s bankruptcy proceeding. This offer is substantially higher than the $108 million that Sacramento Municipal Utility District (SMUD) offered in 2005, and not far below the $400 million that PG&E countered with.

San Francisco offered $2.5 billion for PG&E’s system, and San Jose announced that it also will make a bid. Municipalities believe that the bankruptcy court will be more receptive to accepting the offers as a means of raising cash for the bankrupt utility.