The following is a contributed article by managing partner Ray Gifford and partner Matt Larson at the Denver office of Wilkinson Barker Knauer LLP.
“La -Di-Da-Di (We like to Party)” by Slick Rick and Doug E. Fresh became the song of the summer in 1985, but classics never die. It deserves a reprise as the anthem for the waning summer of 2022 if you happen to own renewable energy in organized markets this summer. Because, boy, are they getting to party.
The party is happening because of the single-clearing price rule in organized markets. Mind you, this is not a knock on renewable energy developers and owners — they play by and benefit from the rules fairly and squarely; so, going to the other coast of hip-hop, “don’t hate the player,” as Too Short says. It is, however, a knock on “markets” that create windfalls for some, squeeze capacity in turn, and — in the end — burden customers who get to pay it. And when customers get mad, regulators and politicians follow that anger to policy choices that we can hope will be more prudent than rash.
The rule of a single-clearing price auction has its basis in sound economic reasoning. When a homogenous, undifferentiated commodity product is being auctioned off, that auction should clear for all participants at the price set by the last marginal producer that satisfies market demand. Thus, if power prices are clearing at $30 a megawatt hour (a rough average of historic organized market clearing prices), then all producers supplying that demand get that market clearing price. Fair enough. In recent times, because of the natural gas revolution, it has been gas units, and specifically, older combustion turbine units that usually set the market clearing price based on their cost to run and fuel cost.
Fast-forward to this summer and those fuel prices were increasing. What does that mean?
Assume a gas price change from $3/MMBtu to $8/MMBtu. That means that instead of a $30 a megawatt hour average market clearing price, producers are getting a price keyed off $8/MMBtu natural gas versus $3/MMBtu. EIA’s Short Term Energy Outlook from June paints the picture: “We forecast that electricity prices in the Northeast regions (ISO New England, New York ISO, and PJM markets) will exceed $100 per megawatt-hour between June and August 2022, up from an average of about $50/MWh last summer. We forecast summer electricity prices will average $98/MWh in California's CAISO market and $90/MWh in the ERCOT market in Texas.” Wholesale prices are nearly tripling from last summer in the Northeast, and roughly doubling everywhere else, says EIA. Prices are high and going higher.
These margins are going two places: fuel suppliers and the owners of low marginal cost generation who can earn these margins with a bid of $0 into the electricity markets. Gas generators, meanwhile, earn an expected return as the marginal producer, but those units will be clearing at a price close to or at the cost of actual electricity production.
In turn, this creates a longer-term feedback loop in the “market” that informs generators that the profit margins come from variable energy with low marginal costs. The problem here is not renewable resources, which play an imperative role in decarbonizing the electric system. The problem is the market, and those markets are being broken by clearing all resources at a single price, even though they have quite different attributes. And do not just take it from us; this paper from an industrial customer organization and former RTO/ISO executive says something similar — just with more detail, less hip-hop, and two diverse backgrounds and perspectives coming together to reach the same conclusion. FERC Commissioner Mark Christie is raising similar issues, recommending a general proceeding that examines the “continued use of single-clearing price mechanisms in RTO markets.”
The situation is going to become intolerable as costs stack up in customers’ bills. A look abroad provides a telltale sign.
As a brief background, Australia deregulated its wholesale power supply market and established the Australian Energy Market Operator. or AEMO, and the United Kingdom also embraced the restructured model. Both are grappling with the effects of the single-clearing price electricity auctions in exacerbating power affordability challenges
The AEMO has implemented the ultimate ‘around market’ solution — a suspension of the market and a takeover of it because “the power system was becoming unmanageable.” Across the pond in the birthplace of Slick Rick himself, the government is expressing deep concern about the price of electricity and its interrelationship with the marginal cost of gas production, as opposed to the actual cost of generation. And the European Union is actively moving toward a solution where non-gas generators’ revenue is capped with the EU then redistributing the economic rents that would have gone to those generators to businesses and customers. In the name of reforming the market, the EU enables itself to take on social welfare policy on-the-fly.
Back home and again, this is not an attack on renewable energy. To the contrary, wind and solar owners did not set the market rules. Those rules date from a time when the generation portfolios were a largely uniform, undifferentiated set of fossil and nuclear resources. The single-clearing price auction was the right answer then, but it is no longer the right answer for customers.
What are the solutions?
First, the markets need to take a page from Lord Keynes’ apocryphally attributed quotation that “When the facts change, I change my mind. What do you do, sir?”
A single clearing price auction is no longer a viable or desirable way to sell power. To put it in regulatory-speak, the prices emanating from single-price auctions are no longer “just and reasonable.” This is because the power market is now segmented into differentiated products. First, there is dispatchable generation like fossil, nuclear, and (to a lesser extent) storage that has attributes where it will show up when customers demand it. Second, there is non-dispatchable, variable generation that shows up when conditions allow. Markets clearing at a single price need to have homogenous products being sold into them, but this is no longer the case. While all electrons ultimately show up on the grid as an undifferentiated mass, the attributes they bring with them are different.
The answer to what comes next is by no means easy or clear though. Reports from the U.K., the European Union, and Australia point to some sort of segmented bidding differentiating between dispatchable and non-dispatchable generation. But this becomes thorny quickly because some sort of around-market actor — the market operator itself — will need to pre-specify the attributes and respective demand curves for each bucket of differently attributed resources.
This means that the resource mix between variable and dispatchable resources ultimately is going to be set through a planning exercise — meaning an IRP at the state level or an IRP-like-process-that-dare-not-be-acknowledged within the “market” context. Introducing more hidden and back-door assumptions to fine-tune a “market” outcome sounds like the same set of political economy incentives that were once used to assail the state-based IRP planning model.
While state efforts creating zero-emission credits to save nuclear units within RTO markets are a controversial tool for internalizing beneficial attributes not captured within marginal cost pricing models, that would be the path policymakers would be on in segmenting the current market construct. Seems hardly worth it, except as a face-saving exercise for the “market” construct.
An alternative step, and one that would be about as popular as telling a Texan that the ERCOT market may not be all it is cracked up to be, would be to go back to what must be acknowledged explicitly or implicitly: that a planning model must be embraced and validated to maintain resource adequacy and affordability in such a differentiated generation market. In a planned model, the variable generators do not get to earn outsized profits from an anomalous auction process. They do cover their costs, which is often the lowest on the system. The customers, in turn, get that cheap(er) power without paying a premium or jeopardizing grid stability.
“La Di Da Di” was released as the B-side to “The Show” where Slick Rick opens by saying to Doug E. Fresh:
Have you ever seen a show with fellas on the mic
With one-minute rhymes that don't come out right?
Some energy markets are currently producing prices that don’t come out right. For consumers, they bite. As customers get their latest bills, they will bite for politicians and regulators too.