Streetwise Professor

In the aftermath of the Texas Freeze-ageddon much ink and many pixels have been spilled about its causes. Much–most?–of the blame focuses on Texas’s allegedly laissez faire electricity market design.

I have been intensely involved (primarily in a litigation context) in the forensic analysis of previous extreme electricity market shocks, including the first major one (the Midwest prices spike of June 1998) and the California crisis. As an academic I have also written extensively about electricity pricing and electricity market design. Based on decades of study and close observation, I can say that electricity market design is one of the most complex subjects in economics, and that one should step extremely gingerly when speaking about the topic, especially as it relates to an event for which many facts remain to be established.

Why is electricity market design so difficult? Primarily because it requires structuring incentives that effect behavior over both very long horizons (many decades, because investments in generation and transmission are very long lived) and extremely short horizons (literally seconds, because the grid must balance at every instant in time). Moreover, there is an intimate connection between these extremely disparate horizons: the mechanisms designed to handle the real time operation of the system affect the incentives to invest for the long run, and the long run investments affect the operation of the system in real time.

Around the world many market designs have been implemented in the approximately 25 year history of electricity liberalization. All have been found wanting, in one way or another. They are like Tolstoy’s unhappy families: all are unhappy in their own way. This unhappiness is a reflection of the complexity of the problem.

Some were predictably wretched: California’s “reforms” in the 1990s being the best example. Some were reasonably designed, but had their flaws revealed in trying conditions that inevitably arise in complex systems that are always–always–subject to “normal accidents.”

From a 30,000 foot perspective, all liberalized market designs attempt to replace centralization of resource allocation decisions (as occurs in the traditional integrated regulated utility model) with allocation by price. The various systems differ primarily in what they leave to the price system, and which they do not.

As I wrote in a chapter in Andrew Kleit’s Energy Choices (published in 2006) the necessity of coordinating the operation of a network in real time almost certainly requires a “visible hand” at some level: transactions costs preclude the coordination via contract and prices of hundreds of disparate actors across an interconnected grid in real time under certain conditions, and such coordination is required to ensure the stability of that grid. Hence, a system operator–like ERCOT, or MISO, or PJM–must have residual rights of control to avoid failure of the grid. ERCOT exercised those residual rights by imposing blackouts. As bad as that was, the alternative would have been worse.

Beyond this core level of non-price allocation, however, the myriad of services (generation, transmission, consumption) and the myriad of potential conditions create a myriad of possible combinations of price and non-price allocation mechanisms. Look around the world, and you will see just how diverse those choices can be. And those actual choices are just a small subset of the possible choices.

As always with price driven allocation mechanisms, the key thing is getting the prices right. And due to the nature of electricity, this involves getting prices right at very high frequency (e.g., the next five minutes, the next hour, the next day) and at very low frequency (over years and decades). This is not easy. That is why electricity market design is devilish hard.

One crucial thing to recognize is that constraints on prices in some time frames can interfere with decisions made over other horizons. For example, most of the United States (outside the Southeast) operates under some system in which prices day ahead or real time are the primary mechanism for scheduling and dispatching generation over short horizons, but restrictions on these prices (e.g., price caps) mean that they do not always reflect the scarcity value of generating or transmission capacity. (Much of the rest of the world does this too.) As a result, these prices provide too little incentive to invest in capacity, and the right kinds of capacity. The kludge solution to this is to create a new market, a capacity market, in which regulators decide how much capacity of what type is needed, and mandate that load servers acquire the rights to such capacity through capacity auctions. The revenues from these auctions provide an additional incentive for generators to invest in the capacity they supply.

The alternative is a pure energy market, in which prices are allowed to reflect scarcity value–and in electricity markets, due to extremely inelastic demand and periodic extreme inelasticity of supply in the short run, that scarcity value can sometimes reach the $1000s of dollars.

Texas opted for the energy market model. However, other factors intervened to prevent prices from being right. In particular, heavy subsidies for renewables have systematically depressed prices, thereby undercutting the incentives to invest in thermal generation, and the right kind of thermal generation. This can lead to much bigger price spikes than would have occurred otherwise–especially when intermittent renewables output plunges.

Thus, a systematic downward price distortion can greatly exacerbate upward price spikes in a pure energy model. That, in a nutshell, is the reason for Texas’s recent (extreme) unhappiness.

As more information becomes available, it is clear that the initiator of the chain of events that left almost half the state in the dark for hours was a plunge in wind generation due to the freezing of wind turbines. Initially, combined cycle gas generation ramped up output dramatically to replace the lost wind output. But these resources could not sustain this effort because the cold-related disruptions in gas production, transmission, and distribution turned the gas generators into fuel limited resources. The generators hadn’t broken down, but couldn’t obtain the fuel necessary to operate.

It is certainly arguable that Texas should have recognized that the distortion in prices that arose from subsidization of wind (primarily at the federal level) that bore no relationship whatsoever to the social cost of carbon made it necessary to implement the kapacity market kludge, or some other counterbalance to the subsidy-driven wrong prices. It didn’t, and that will be the subject of intense debate for months and years to come.

It is essential to recognize however, that the underlying reason why a kludge may be necessary is that the price wasn’t right due to government intervention. When deciding how to change the system going forward, those interventions–and their elimination–should be front and center in the analysis and debate, rather than treated as sacrosanct.

There is also the issue of state contingent capacity. That is, the availability of certain kinds of capacity in certain states of the world. In electricity, the states of the world that matter are disproportionately weather-related. Usually in Texas you think of hot weather as being the state that matters, but obviously cold weather matters too.

It appears that the weatherization of power plants per se was less of an issue last week than the weatherization of fuel supplies upstream from the power plants. It is an interesting question regarding the authority of ERCOT–the operator of the Texas grid–extends to mandating the technology utilized by gas producers. My (superficial) understanding is that it is unlikely to, and that any attempt to do so would lead to a regulatory turf battle (with the Texas Railroad Commission, which regulates gas and oil wells in Texas, and maybe FERC).

There is also the question of whether in an energy only market generators would have the right incentive to secure fuel supplies from sources that are more immune to temperature shocks than Texas’s proved to be last week. Since such immunity does not come for free, generator contracts with fuel suppliers would require a price premium to obtain less weather-vulnerable supplies, and presumably a liability mechanism to penalize non-performance. The price premium is likely to be non-trivial. I have seen estimates that weatherizing Texas wells would cost on the order of $6-$9 million per well—which would double or more than the cost of a well. Further, it would be necessary to incur additional costs to protect pipelines and gas processing facilities.

In an energy only market, the ability to sell at high prices during supply shortfalls would provide the incentive to secure supplies that allow producing during extreme weather events. The question then becomes whether this benefit times the probability of an extreme event is larger or smaller than the (non-trivial) cost of weatherizing fuel supply.

We have a pretty good idea, based on last week’s events, of what the benefit is. We have a pretty good idea of the cost of hardening fuel supplies and generators. The most imprecise input to the calculation is the probability of such an extreme event.

Then the question of market design–and specifically, whether weatherization should be mandated by regulation or law, and what form that mandate should take–becomes whether generation operators or regulators can estimate that probability more accurately.

In full awareness of the knowledge problem, my priors are that multiple actors responding to profit incentives will do a better job than a single actor (a regulator) operating under low power incentives, and subject to political pressure (exerted by not just generators, but those producing, processing, and transporting gas, industrial consumers, consumer lobbyists, etc., etc., etc., as well). Put differently, as Hayek noted almost 75 years ago, the competitive process and the price system is a way of generating information and using it productively, and has proved far more effective in most circumstances than centralized planning.

I understand that this opinion will be met with considerable skepticism. But note a few things. For one, a regulator’s mistakes have systematic effects. Conversely, some private parties may overestimate the risk and others underestimate it: the composite signal is likely to be more accurate, and less vulnerable to the miscalculation of a single entity. For another, on the one hand skeptics excoriate a regulator for its failures–but confidently predict that some other future regulator will get it right. I’m the skeptic on that.

Recent events also raise another issue that could undermine reliance on the price system. Many very unfortunately people entered into contracts in which their electricity bills were tied to wholesale prices. As a result, the are facing bills for a few days of electricity running into the many thousands of dollars because wholesale prices spiked. This is indeed tragic for these people.

That spike by the way, is up to $10,000/MWh. $10/KWh. Orders of magnitude bigger than you usually pay.

It is clear that the individuals who entered these contracts did not understand the risks. And this is totally understandable: if you are going to argue that regulators or generators underplayed the risks, you can’t believe that they typical consumer won’t too. I am sure there will be lawsuits relating in particular to the adequacy of disclosure by the energy retailers who sold these contracts. But even if the fine print in the contracts disclosed the risks, many consumers may not have understood them even if they read it.

One of the difficulties with getting prices right in electricity markets which has plagued market design is getting consumers to see the price signals so that they can limit use when supply is scarce. But this will periodically involve paying stratospheric prices.

From a risk bearing perspective this is clearly inefficient. The risk should be transferred to the broader financial markets (though hedging mechanisms, for instance) because the risk can be diversified and pooled in those markets. But this is at odds with the efficient consumption perspective. This is not a circle that anyone has been able to square heretofore.

Moreover, the likely regulatory response to the extreme misfortune experienced by some consumers will be to restrict wholesale prices so that they do not reflect scarcity value. That is, an energy only market has a serious time consistency problem: regulators cannot credibly commit to allow prices to reflect scarcity value, come what may. This means that an energy only market may not be politically sustainable, regardless of its economic merits. I strongly suggest that this will happen in Texas.

In sum, as the title of the book I mentioned earlier indicates, electricity market design is about choices. Moreover, those choices are often of the pick-your-poison variety. This means that avoiding one kind of problem–like what Texas experienced–just opens the door to other problems. Evaluation of electricity market design should not over-focus on the most recent catastrophe while being blind to the potential catastrophes lurking in alternative designs. But I realize that’s not the way politics work, and this will be an intensely political process going forward. So we are likely to learn the wrong lessons, or grasp at “solutions” that pose their own dangers.

As a starting point, I would undo the most clearcut cause of wrong prices in Texas–subsidization of wind and other renewables. Alas, even if stopped tomorrow the baleful effect those subsidies will persist long into the future, because they have impacted decisions (investment decisions) on the long horizon I mentioned earlier. But other measures–such as mandated reserve margins and capacity markets, or hardening fuel supplies–will also only have effects over long horizons. For better or worse, and mainly worse, Texas will operate under the shadow of political decisions made long ago. And made primarily in DC, rather than Austin.