Tag Archives: energy economics

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.

 

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?

Our responsibility to our children

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Greta Thunberg’s speech at the UN has sparked a discussion about our deeper responsibilities to our future generations. When we made the huge effort to fight World War II, did we ask “how much will this cost?” We face the same existential threat and should make the same commitment. We can do this cost effectively, and avoid making most stupid decisions, but asking whether this effort is worth it is now beyond question. We will have to consider how to compensate those who have invested their money or their livelihoods in activities that we now recognize as damaging to the climate, and that will be an added cost to the rest of us. (And we may see this as unfair.) But we really have no choice.

J. Frank Bullit posted on “Fox and Hounds” a sentiment that reflects the core of opposition to such actions:

What if the alarmists are wrong, yet there is no counter to the demands of enacting economic and energy policies we might regret?”

So our energy costs might be a bit more than it would have otherwise, but we get a cleaner environment in exchange. And even now, renewable energy sources are competing well on a dollar to dollar basis.

On the other hand, if the “alarmists” are correct, the consequences have a significant probability of being catastrophic to our civilization, as well as our environment. We all have insurance on our houses for events that we see as highly unlikely. We pay that extra cost on our house to gain assurance that we will recover our investments if such unlikely events occur. These are costs that we are willing to accept because we know that the “alarmists” have a point about the risks of house fires. We should be taking the same attitude towards climate change assessments. It’s not possible to prove that there is no risk, or even that the risk is tiny. And the data trends are sufficiently consistent with the forecasts to date that the probabilities weigh more towards a likelihood than not.

Unless opponents can show that the consequences of the alarmists being wrong are worse than the climate change threat, we have to act to mitigate that risk in much the same way as we do when we buy house insurance. (And by the way, we don’t have another “house” to move to…)

U. of Chicago misses mark on evaluating RPS costs

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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?

Moving beyond the easy stuff: Mandates or pricing carbon?

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Meredith Fowlie at the Energy Institute at Haas posted a thought provoking (for economists) blog on whether economists should continue promoting pricing carbon emissions.

I see, however, that this question should be answered in the context of an evolving regulatory and technological process.

Originally, I argued for a broader role for cap & trade in the 2008 CARB AB32 Scoping Plan on behalf of EDF. Since then, I’ve come to believe that a carbon tax is probably preferable over cap & trade when we turn to economy wide strategies for administrative reasons. (California’s CATP is burdensome and loophole ridden.) That said, one of my prime objections at the time to the Scoping Plan was the high expense of mandated measures, and that it left the most expensive tasks to be solved by “the market” without giving the market the opportunity to gain the more efficient reductions.

Fast forward to today, and we face an interesting situation because the cost of renewables and supporting technologies have plummeted. It is possible that within the next five years solar, wind and storage will be less expensive than new fossil generation. (The rest of the nation is benefiting from California initial, if mismanaged, investment.) That makes the effective carbon price negative in the electricity sector. In this situation, I view RPS mandates as correcting a market failure where short term and long term prices do not and cannot converge due to a combination of capital investment requirements and regulatory interventions. The mandates will accelerate the retirement of fossil generation that is not being retired currently due to mispricing in the market. As it is, many areas of the country are on their way to nearly 100% renewable (or GHG-free) by 2040 or earlier.

But this and other mandates to date have not been consumer-facing. Renewables are filtered through the electric utility. Building and vehicle efficiency standards are imposed only on new products and the price changes get lost in all of the other features. Other measures are focused on industry-specific technologies and practices. The direct costs are all well hidden and consumers generally haven’t yet been asked to change their behavior or substantially change what they buy.

But that all would seem to change if we are to take the next step of gaining the much deeper GHG reductions that are required to achieve the more ambitious goals. Consumers will be asked to get out of their gas-fueled cars and choose either EVs or other transportation alternatives. And even more importantly, the heating, cooling, water heating and cooking in the existing building stock will have to be changed out and electrified. (Even the most optimistic forecasts for biogas supplies are only 40% of current fossil gas use.) Consumers will be presented more directly with the costs for those measures. Will they prefer to be told to take specific actions, to receive subsidies in return for higher taxes, or to be given more choice in return for higher direct energy use prices?

Reverse auctions for storage gaining favor

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Two recent reports highlight the benefits of using “reverse auctions”. In a reverse auction, the buyer specifies a quantity to be purchased, and sellers bid to provide a portion of that quantity.  An article in Utility Dive summarizes some of the experiences with renewable market auctions.  A separate report in the Review of Environmental Economics and Policy goes further to lay out five guidelines:

  1. Encourage a Large Number of Auction Participants
  2. Limit the Amount of Auctioned Capacity
  3. Leverage Policy Frameworks and Market Structures
  4. Earmark a Portion of Auctioned Capacity for Less-mature Technologies
  5. Balance Penalizing Delivery Failures and Fostering Competition

This policy prescription requires well-informed policy makers balancing different factors–not a task that is well suited to a state legislature. How to develop such a coherent policy can done in two ways. The first is to let the a state commission work through a proceeding to set an overall target and structure. But perhaps a more fruitful approach would be to let local utilities, such as California’s community choice aggregators (CCAs) to set up individual auctions, maybe even setting their own storage targets and then experimenting with different approaches.

California has repeatedly made errors by overly relying on centralized market structures that overcommit or mismatch resource acquisition. This arises because a mistake by a single central buyer is multiplied across all load while a mistake by one buyer within a decentralized market is largely isolated to the load of that one buyer. Without perfect foresight and a distinct lack of mechanisms to appropriately share risk between buyers and sellers, we should be designing an electricity market that mitigates risks to consumers rather than trying to achieve a mythological “optimal” result.

Relying on short term changes diminishes the promise of energy storage

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I posted this response on EDF’s blog about energy storage:

This post accepts too easily the conventional industry “wisdom” that the only valid price signals come from short term responses and effects. In general, storage and demand response is likely to lead to increased renewables investment even if in the short run GHG emissions increase. This post hints at that possibility, but it doesn’t make this point explicitly. (The only exception might be increased viability of baseloaded coal plants in the East, but even then I think that the lower cost of renewables is displacing retiring coal.)

We have two facts about the electric grid system that undermine the validity of short-term electricity market functionality and pricing. First, regulatory imperatives to guarantee system reliability causes new capacity to be built prior to any evidence of capacity or energy shortages in the ISO balancing markets. Second, fossil fueled generation is no longer the incremental new resource in much of the U.S. electricity grid. While the ISO energy markets still rely on fossil fueled generation as the “marginal” bidder, these markets are in fact just transmission balancing markets and not sources for meeting new incremental loads. Most of that incremental load is now being met by renewables with near zero operational costs. Those resources do not directly set the short-term prices. Combined with first shortcoming, the total short term price is substantially below the true marginal costs of new resources.

Storage policy and pricing should be set using long-term values and emission changes based on expected resource additions, not on tomorrow’s energy imbalance market price.