In part 1 of this article, I wrote about the importance of demand response in the electricity industry – i.e., why power companies might choose to pay customers to use less electricity at certain times. Here, I discuss what the right price for demand response would be, and a recent US Supreme Court case over the fundamental economic principles of that price – including the question of whether reducing consumption was equivalent to generation.
When companies offer demand response programs, the offer needs to be simple, compelling and easy to understand for customers. Demand response is typically used only a few times per year, so it is not worth customers spending the time and effort to learn a complex price scheme. You might also ask, what is the point of demand response as a separate scheme? We already have a wholesale market. If the price gets very high, then people will reduce their consumption. There is more that can be said on this, but one point of separate demand response schemes is to target customers who are not able, or not interested, to respond to wholesale market prices in real time. So demand response schemes are offered in different ways that make sense for different customers. In part 1, I described a scheme to pay people cash up front in return giving the distributor Energex the ability to remotely turn down their air conditioner at certain times. Another example will be trialled by the retailer Powershop this summer, supported by The Australian Energy Market Operator (AEMO) and Australian Renewable Energy Agency (ARENA). Powershop will use a smart phone app to tell people to reduce their demand at certain times, with the reward being a certain about of free electricity at other times.
With these indirect schemes, it is often difficult to calculate the exact price in $/MWh being offered to customers. That’s probably fine if both buyer and seller are happy with the deal. But is there are a “correct” price? Given that demand response is something of an alternative to the wholesale market, the correct price probably has to do with the wholesale market price, right?
Let us give a specific example. If a person normally pays $50/MWh for their electricity use, and prices rise to $500/MWh … how much should they be paid if they use less electricity than they normally would?
- $500/MWh for each MWh of reduced demand (the current price), or
- $450/MWh (the current price minus the customer’s usual retail price)?
This was argued in a 2016 Supreme court case, where the two sides disagreed on the fundamental economic theory of the question. The case was significant because this was not an example of a buyer and seller mutually agreeing on price, but an example of when the government was forcing power system operators to pay demand response providers a particular price, even if the operators did not agree with that price.
In the case, FERC (the US regulator) had created a demand response program that required energy market operators to pay the current price ($500/MWh in the above example). The EPSA (a generator industry group) was opposed to the demand response scheme, and argued that:
- In the EPSA’s view, FERC did not have the legal authority to create a demand response scheme, and
- That if FERC did have the authority, then the compensation should be the current price minus the normal price for the customer ($450/MWh in the above example).
What I think was amazing about the case was that all these famous economic professors then wrote submissions to the court, arguing the economic theory of what the price should be. Harvard economics professor Bill Hogan contributed a “friend of the court” brief in support of the EPSA, arguing that FERC was forcing grid operators to overpay for demand response by, in the example above, forcing them to pay $500/MWh.
Here is an extract from Hogan’s brief:
“To offer an analogy, consider a manufacturer that produces an automobile it can sell to a dealer for $20,000; the dealer has agreed to then sell the automobile to a customer at cost ($20,000), but cars are in high demand and another customer wants to buy the car for $30,000. No one would say that the first customer should be paid $30,000 for not buying the car, just because another customer wants it or cars are in short supply. If one customer has a right to buy the car at $20,000, while another is willing to pay $30,000–and lack of supply means that both cannot purchase cars–the dealer could, in theory, sell the car to the second customer and give the first customer the $10,000 difference between the market price and the price at which she has the right to purchase. That would allocate the car to the customer who values it more, while giving the first customer an incentive to allow the second customer to have it. We would never, however, say that the dealer must: (1) pay the manufacturer $30,000; (2) pay the first customer $30,000 (the car’s current value) for not buying the car; and (3) sell the car at $30,000 (again its current value) for a loss. But that is what FERC effectively has done: It provides the first customer with a windfall while requiring [grid operators] to pay twice (to the electricity producer and the non-buyer) for a unit of electricity that they may only sell once for less than the total price paid.”
However, in an earlier affidavit, Professor Kahn of Cornell University argued (and FERC agreed), that reducing demand was equivalent to increasing generation, and should receive the same compensation, meaning that the $500/MWh would be the correct price above. From Kahn’s affidavit:
“Demand response is in all essential respects economically equivalent to supply response; and that economic efficiency requires, that it should be rewarded with the same [price] that clears the market. Since DR is actually–and not merely metaphorically–equivalent to supply response, economic efficiency requires that it be regarded and rewarded, equivalently, as a resource proffered to system operators, and be treated equivalently to generation in competitive power markets.”
What do you think? It is a subtle difference. In the above example, the $450/MWh case is equivalent to the customer buying electricity at their regular price of $50/MWh, and immediately selling it to the market at the market price of $500/MWh, for a profit of $450/MWh, instead of using the electricity themselves.
In the end the Supreme court did not endorse any particular price method. By a 6–2 verdict, the court decided that:
- FERC did have the legal authority to run a demand response scheme, and
- That FERC also had the authority to set the price in that scheme, and therefore (even though both sides had made good points) FERC’s price should be used.
What do I think? I admit that I am not an expert in these matters – nothing like the experts quoted above – but for what is worth, my view is that Hogan’s argument is correct, and that $450/MWh would be the correct price. From my perspective, demand response by a customer is equivalent to selling their right to use electricity to someone else. To do that, they need to have the right to use electricity, and if they have to pay $50/MWh to obtain that right (and hence receive $450/MWh overall), then that is what they need to do.
However, I acknowledge that there are other benefits to demand response schemes than avoiding wholesale market costs. For example, demand response schemes at times of high network demand also reduce the costs of “poles and wires”, and that the financial benefits of reducing network costs could even exceed those of wholesale costs. (Note that in the air-conditioner example above, the scheme is offered by the distributor Energex (a network operator) rather than the wholesale market operator AEMO). Network costs are recovered very inefficiently in general, mostly through simple charges. A demand response scheme with non-ideal prices could still benefit the public overall. Another submission to the court, from Charles Kolstad, an economist at Stanford University, argued in favour of FERC because the public was better off with demand response than without it, even if the non-ideal FERC method was used. Note that there were also implementation challenges with the EPSA method that I haven’t described, such as the need for the market operator to know the normal price paid the customer. (There are other details which I have omitted, and if you’re interested I recommend reading the references below).