Tag Archives: electricity rates

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.

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.

Should California just buy PG&E?


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


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.

CPUC proposes radical restructuring of PG&E

104778251-gettyimages-861000956In PG&E’s safety order institution investigation (OII), outgoing CPUC President Michael Picker (along with senior administrative law judge Peter Allen) has put on the table four dramatic proposals to address governance and incentive issues at the utility. These proposals are:

  1. Separating PG&E into separate gas and electric utilities or selling the gas assets;
  2. Establishing periodic review of PG&E’s Certificate of Convenience and Necessity (CPCN);
  3. Modification or elimination of PG&E Corp.’s holding company structure; and
  4. Linking PG&E’s rate of return or return on equity to safety performance metrics.

The OII originally was opened to investigate PG&E’s management of its natural gas infrastructure, but the series of electricity-sparked wildfires reinfused the OII with a new direction. The proceeding has been a forum for various dramatic proposals on how to handle wildfire-related issues and PG&E’s subsequent bankruptcy filing.


Not grasping the concept: PG&E misses the peak load shift

Utility peak shifted by solar graph

PG&E in its 2020 ERRA Forecast Proceeding testimony wrote “however, BTM DG [behind the meter distributed generation] has a limited impact to the annual system peak as customer-owned solar photovoltaic (PV) generation is minimal during the peak hour of 7 p.m.” Uh, how does PG&E know that customer-owned solar doesn’t contribute to reducing the system peak if PG&E does not meter that generation?

PG&E actually has it wrong. Customer-owned solar has in fact reduced the former pre-solar peak that used to occur between 2 and 4 p.m. The metered load that PG&E can see, which is customer usage minus solar output (BTM DG), has shifted its apparent peak from 4 p.m. to 7 p.m.–3 hours. The graphic above illustrates how this shift has occurred. (PG&E produced a similar chart of its 2016 loads in its TOU rate rulemaking.) So BTM DG has had a profound impact on the annual system peak.

U. of Chicago misses mark on evaluating RPS costs


The U. of Chicago just released a working paper “Do Renewable Portfolio Standards Deliver?” that purports to assess the added costs of renewable portfolio standards adopted by states. The paper has two obvious problems that make the results largely useless for policy development purposes.

First, it’s entirely retrospective and then tries to make conclusions about future actions. The paper ignores that the high initial costs for renewables was driven down by a combination of RPS and other policies (e.g. net energy metering or NEM), and on a going forward basis, the renewables are now cost competitive with conventional resources. As a result, the going forward cost of GHG reductions is much smaller than the historic costs. In fact, the much more interesting question is “what would be the average cost of GHG reductions by moving from the current low penetration rate of renewables to substantially higher levels across the entire U.S., e.g., 50%, 60% etc. to 100%?” The high initial investment costs are then highly diluted by the now cost effective renewables.

Second, the abstract makes this bizarre statement “(t)hese cost estimates significantly exceed the marginal operational costs of renewables and likely reflect costs that renewables impose on the generation system…” Um, the marginal “operational” costs of renewables generally is pretty damn close to zero! Are the authors trying to make the bizarre claim (that I’ve addressed previously) that renewables should be priced at their “marginal operational costs”? This seems to reflect an remarkable naivete on the part of the authors. Based on this incorrect attribution, the authors cannot make any assumptions about what might be causing the rate difference.

Further, the authors appear to attribute the entire difference in rates to imposing an RPS standard. The fact is that these 29 states generally have also been much more active in other efforts to promote renewables, including for customers through NEM and DER rates, and to reduce demand. All of these efforts reduce load, which means that fixed costs are spread over a fewer amount of kilowatt-hours, which then causes rates to rise. The real comparison should be the differences in annual customer bills after accounting for changes in annual demand.

The authors also try to assign stranded cost recovery as a cost of GHG recovery. This is a questionable assignment since these are sunk costs which economists typically ignore. If we are to account for lost investment due to obsolescence of an older technology, economists are going to have go back and redo a whole lot of benefit-cost analyses! The authors would have to explain the special treatment of these costs.

Why do economists keep producing these papers in which they assume the world is static and that the future will be just like the past, even when the evidence of a rapidly changing scene is embedded in the data they are using?

The Business Roundtable takes the wrong lesson from California’s energy costs


The California Business Roundtable authored an article in the San Francisco Chronicle claiming that the we only need to look to California’s energy prices to see what would happen with the “Green New Deal” proposed by the Congressional Democrats.

That article has several errors and is misleading in others aspects. First, California’s electricity rates are high because of the renewable contracts signed nearly a decade ago when renewables were just evolving and much higher cost. California’s investment was part of the reason that solar and wind costs are now lower than existing coals plants (new study shows 75% of coal plants are uneconomic) and competitive with natural gas. Batteries that increase renewable operations have almost become cost effective. It also claims that reliability has “gone down” when in fact we still have a large reserve margin. The California Independent System Operator in fact found a 23% reserve margin when the target is only 17%. We also have the ability to install batteries quickly to solve that issue. PG&E is installing over 500 MW of batteries right now to replace a large natural gas plant.

For the rest of the U.S., consumers will benefit from these lower costs today. Californians have paid too much for their power to date, due to mismanagement by PG&E and the other utilities, but elsewhere will be able to avoid these foibles.

(Graphic: BNEF)