Who’s Stranded Now?
Utility costs are like taxes. Everyone knows they have to be paid, but most people have a reason that their own share should be smaller. And, just as with taxes, there are limitless ways to divide up the revenue burden.
It’s been 20 years since electricity deregulation raised the specter of stranded utility costs – past investments that have turned out to deliver less value than was originally expected — and the question of who should pay those costs: Electricity ratepayers? Customers switching to buy from a competing electricity supplier? Utility shareholders?
So now it’s 2016 and we are back to the same question. Electricity customers are leaving or are greatly reducing purchases. Some customers are installing rooftop solar while still buying some power from the utility. Others are switching to a community choice provider (as I discussed in February) or proposing municipalization. As utility sales decline, once again we are debating who should pay for utility investments that are less valuable in the new regime.
Utilities are responding mostly as they did in the 1990s, arguing that their investments were deemed prudent by regulators at the time they were made, so their own shareholders should not be on the hook. In somber tones they invoke a “regulatory compact” that is supposed to assure them a reasonable return on investments in exchange for an obligation to provide safe, affordable, reliable service. Basically, they argue, a deal’s a deal, even when the market or regulatory environment changes in ways that devalue their installed capital.
Opponents respond by saying “Not so fast. Utility shareholders have received investment returns comparable to the rates earned by unregulated companies while bearing far less risk. Yes, the market is changing and that is hurting your company. Welcome to a world with some risk.” And furthermore, the reply continues, the utility commissions that approved those investments were too cozy or politically connected with the utilities, so the deals made shouldn’t be binding.
Both arguments have some merit. Regulators should try to fulfill commitments, out of fairness, to maintain credibility, and to create a financial environment that can support investment. But if the regulatory process that made those commitments was so broken that it was not legitimate, then the argument for sticking with unfair commitments is less compelling.
So it has been ironic to now see the arguments of each side flip as regulators reconsider some of the terms set for the current wave of partially exiting customers.
In December 2015, regulators in Nevada changed the rules for rooftop solar, abandoning net metering both for new installations and for customers who already have panels on their roofs. The decision followed another ruling in Arizona that reduced incentives to install rooftop solar. The howls of protest from solar customers included many references to unfairly changing the rules, even though there was no explicit long-term commitment to those rules, just expectations.
While Nevada was rocking the DG world, California was considering many of the same issues, and the solar advocates’ arguments on net metering policies followed along similar lines: the state has made a commitment to building rooftop solar and breaking that commitment would have dire consequences.
In California, the advocates were mostly victorious. Net metering was extended for a few years, though the commissioners suggested they could follow Nevada next time if they don’t see more evidence solar customers are paying their fair share of costs.
While solar customers viewed these unwritten commitments in California, Nevada and elsewhere as sacrosanct, utilities argued they are over-the-top subsidies that don’t make public policy sense and should be scaled back. More than one utility executive, or manager at a grid-scale renewables company, has complained that subsidies for distributed generation are being driven by the outsize political influence of DG solar companies, and that state regulators have lost sight of the original goals of reducing greenhouse gases while maintaining affordable electricity.
At about the same time as they were reviewing policies towards distributed generation, the California Public Utilities Commission was also resetting exit fees for departing customers who join community choice providers, using a formula that had been established in a previous decision. These fees were created to compensate utilities for the power contracts they signed at what are now above-market prices — many for renewable power contracts in the early, expensive days — and to protect remaining customers from having to cover an unfair share of those contracts. Community choice advocates argued for delaying or abandoning the increase, while the utilities returned to the view that a deal’s a deal.
Watching the different sides repeatedly invoke and abandon the imperative of sticking with policy directions set in previous decisions is a bit like watching the Republicans and Democrats in the Senate fight over legislative procedures. Whichever side is in ascendancy uses the rules to support their agenda, while the opposing side is shocked by the blatant abuse of power. And then instantly the roles reverse when power shifts.
The big difference, of course, is there is no regulatory agency overseeing Congress that can call them on their hypocritical arguments. Electricity regulators can, and should, do so when market participants selectively argue the sanctity of whatever existing policy they support.
That’s not to say that regulators should blithely switch policies ignoring the cost of the uncertainty it creates. Policy consistency is important, up to a point. New information, new analysis, and new technologies, however, constantly alter the energy landscape. Policies that are written with clear dates of future review and potential off ramps may discourage some investment, but they seem just as likely to maintain pressure for verifiable high performance. Given the dynamism in energy technology and climate science, regulators should be extremely cautious about making inflexible policy commitments to specific technologies.
When policies are re-evaluated it is crucial to separate the determination of whether overall a policy merits continuation from the allocation of gains and losses if it is halted. Some party will always lose when policy changes. The regulatory or legal process can determine if losers are due compensation, but that mustn’t be allowed to lock policy into the status quo.
In the next 10 years, we will likely see more change in energy systems than we have seen in the last 50. While government policy should be fair to market participants it must also be nimble and adaptive to a changing landscape. Only with such flexibility will we be able to address the growing environmental impact and affordability challenges that we face.
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Severin Borenstein View All
Severin Borenstein is Professor of the Graduate School in the Economic Analysis and Policy Group at the Haas School of Business and Faculty Director of the Energy Institute at Haas. He received his A.B. from U.C. Berkeley and Ph.D. in Economics from M.I.T. His research focuses on the economics of renewable energy, economic policies for reducing greenhouse gases, and alternative models of retail electricity pricing. Borenstein is also a research associate of the National Bureau of Economic Research in Cambridge, MA. He served on the Board of Governors of the California Power Exchange from 1997 to 2003. During 1999-2000, he was a member of the California Attorney General's Gasoline Price Task Force. In 2012-13, he served on the Emissions Market Assessment Committee, which advised the California Air Resources Board on the operation of California’s Cap and Trade market for greenhouse gases. In 2014, he was appointed to the California Energy Commission’s Petroleum Market Advisory Committee, which he chaired from 2015 until the Committee was dissolved in 2017. From 2015-2020, he served on the Advisory Council of the Bay Area Air Quality Management District. Since 2019, he has been a member of the Governing Board of the California Independent System Operator.
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I would add a fourth wedge to your pie–independent suppliers. A lot of “merchant” conventional generation was developed in California in the early 2000s based on the “regulatory compact” that short-term wholesale markets would allow capital cost recovery. Starting in the mid-2000s, California policy pivoted towards the discriminatory procurement of renewables, other preferred resources, and even new conventional generation through long-term contracts, essentially ensuring that short-term markets would never allow for capital cost recovery and stranding any investment that was made without the support of long-term contracts. Prospectively, rooftop solar installers may have similar stranded investments to the extent that they own the systems that they lease and it is relatively easy for customers to break their leases when and if rates change and they find that they are no longer saving money relative to reliance on their utility for electricity.
Matt, I agree with your points, but don’t know why you and Severin are both scare-quoting “regulatory compact” as if it’s not a real thing or is only semi-legitimate. Language matters, and certainly some people want newcomers to believe that the utility model is some fuzzy gentlemen’s agreement, but it’s not. POLR, obligation to serve, etc, are also real things.
Also real was that when the utilities were racing to procure for RPS, they and everyone knew they were signing contracts that were then above market, and would be even more above market in the future if the CPUC-sought market transformation succeeded. Which it did – huzzah! But I’m not in favor of letting big chunks of departing load avail themselves of contemporary prices while walking away from their share of the policy-directed path that got us there.
“Regulatory compact” at least in California, is a much fuzzier principle than you are letting on. Also, POLR is very much in question in relation to CCAs. And the lack of prudency review by the CPUC can’t be simply used as an excuse for failure to understand how to mitigate and manage risk. The IOUs earn more than the corporate debt rate on their equity because they are taking on risk for these type of issues. And don’t pat yourself on the back too much for market transformation.
I think Chris’ comment is right – there are two issues here – how to create regulatory incentives going forward and another that looks backward at previous ‘incentives’ and how to fairly allocate those ‘commitments’. One example of the latter – not mentioned in your piece – is how to allocate the stranded assess and shut-down costs of the two nuclear units at San Onofre. Last time I looked, the two utilities involved – SoCal Edison and San Diego Gas and Electric – were resisting having the shareholders bear any of that burden, for the reasons you suggest. On the other hand, ‘mistakes were made’ in attempting to rebuild/replace the steam generator tubes that arguably the ratepayers had little say in… (ultimately leading the utilities to pull the plug).
Looking forward, there was a fascinating set of data presented in the SF Chronicle on Saturday, 7/16 in an article about the impact of utility-scale solar and wind on the CA grid. According to the article, the peak power from UTILITY-scale solar on the previous Tuesday (7/12) was 8 GW, along with ~3.5 GW of wind – and the ISO had to curtail some of the utility-scale power production because of limitations in the grid. Not included in these data was the output of over 4 GW of solar arrays on homes and businesses. So the transition that Chris mentions is happening – the question is whether the regulatory environment can keep up, hopefully in a way that can capture the external benefits (and costs) of a renewable energy system.
The article quotes the head of the ISO as saying “We’re changing our paradigm from a grid that is largely traditional [generating] resources augmented by renewables to one that is based on renewables augmented by traditional resources, mostly natural gas.” Presumably the latter is for off-peak load following. So the “traditional” utility operational paradigm – base load and rapidly deployable turbine ‘peakers’ to meet afternoon-early evening summer peak demand is no longer very relevant.
There are two regulatory perspectives here, backwards and forwards. Fairly recovering past investment poses a major regulatory headache, but so does maintaining “a financial environment that can support investment,” as you said, Severin. Technically we’re entering a major transition, as well as economically and financially. In other words, considerable new investment, especially in the distribution network, will be required to facilitate the transition. Further, it seems a new regulatory framework will be needed to stimulate the upgrade, i.e. one not based on sales, or probably not on throughput, in fact, only partially on energy. Some other more meaningful indicator is necessary that recognizes the storage, reliability, and other contributions of the megagrid to microgrids and prosumers. All this makes the NY REV process fascinating.
Why, in virtually all of these discussions, is the fact not mentioned that the distributed solar grid owners are providing power at the time of peak demand and drawing power at the time of generally lowest cost of generation, and yet, at least in my state of Maryland, getting no credit for this at all? And this is the case even when the utility is rewarding traditional users who cut their demand during peak hours a financial premium, and when at least some of the utilities here are offering incentives for using rooftop solar so they do not have to construct an expensive interstate timeline to ensure a sufficient amount of uninterruptible power. Until there is a full discussion of all aspects of the issue, it is hard, in my view, to offer much sympathy to the pleas from the utilities to be reimbursed for providing net metering.
Mike, in general, solar produces during off-peak periods and households tend to consume the most electricity during the peak period. Therein lies the problem for net metering– that the consumers aren’t “paying their fare share.” The California ISO manages most of California’s electricity load. If you take a quick look at the first graph, you’ll notice that electricity demand peaks 4PM-8PM (which is typical for the summer-time), while solar generation peaks 9AM-5PM (see second graph).
http://www.caiso.com/outlook/outlook.html
The CAISO graph shows the load is the same at 3 pm (not 5) as it is at 8 pm, so the backend of the solar peak is covering the start of the CAISO metered peak.
Which brings up the second question–Who’s peak?: the CAISO metered peak which will increasingly shift into the evening as more solar DG is added, or the total CUSTOMER peak load which is either unchanged or even shifting to earlier in the day to take advantage of free solar? The problem isn’t physical–it’s contractual. The markets for the utility-side and customer side of the meter are contractually separated and that leads to arbitrage opportunities. The PHYSICAL peak is the customer end use, and the CAISO metered peak is a contractual artifact.
It is not clear to me from the curves that are referred to if these are the curves that the utilities see or reflect those of both utility and distributed systems together. In the national EIA summaries, the solar generated is only for utility solar (i.e., > 1 MW systems)–all the solar generated by rooftop systems appears in their figures as reduced demand, so they really underestimate the amount of solar derived electricity for our entire economy by about a factor of 2 (based on installed capacity figures they do provide). So, what rooftop solar is doing is covering what would be a quite strong demand for air conditioning, etc. and sharply shaving off the peak demand. I would think that this basically has the effect of somewhat leveling off overall demand (i.e., cutting the really high peak demands on very hot days, etc.) and so likely helps increase the fraction of time that utility resources can be used. I am basically just suggesting that it seems to me hard to understand how there could be no benefit from having homeowners and businesses cutting their peak demands on hot days when combustion is less efficient and the cost per kW-hr is quite high. Well, yes, utilities would likely love to be able to charge for all of this and be guaranteed reimbursement for having lots more equipment sitting idle more of the time. All I am asking is that full consideration be given to the many aspects of the issue.
Professor Borenstein – We live in sunny Davis, but in an old section with lots of old, large trees. When we looked at Solar they wanted to cut down an old Valley Oak. So we decided to wait, possibly for more efficient panels which would need less area. Our electric bills keep going up, I presume due to roof-top solar and renewable mandates. About 50% of our bill is infrastructure, and the rest for electricity production. When solar users send surplus electricity back the PG&E what are they paid? Surely not the total cost, since they use the infrastructure, etc., to send it back?