Hardly a week goes by without someone on #energytwitter speculating that proliferation of zero-marginal-cost variable resources (read: wind and solar) will mean the end of power markets as we know them. After all, how can you base everything on marginal costs when they are zero?
The simple answer is that fuel isn't the only type of marginal cost: the demand side of the market has opportunity costs and storage resources have intertemporal arbitrage opportunities. Even if all supply resources have zero cost, we would still see non-zero prices.
But the story doesn't end there, and it's still possible to argue that power markets in their current form might not work as well with high levels of renewables.
Even if you're not interested in the modeling, you might be curious to read Section 2 of the paper for an overview of these arguments.
In particular, this paper looks at the possibility that even if we get high enough prices on average, they will be so volatile that contracting around them will be exceedingly difficult, necessitating a change in approach.
To assess this possibility, we construct a model where the cost of capital is endogenously determined by interannual volatility in operating profits for supply resources and the degree to which they can hedge that volatility.
When Jesse and I were constructing these numerical tests, we both expected volatility to explode. But the story turned out to be a bit more complicated.
First the bad news: scarcity events do indeed concentrate in a smaller number of the modeled years, leading to higher volatility in profits.
As a result of this volatility, it becomes harder to finance peaking and backup resources in particular, contributing to lower reliability.
But on net, at least with standard estimates of the value of lost load, that's outweighed by the good news: by removing fuel price uncertainty from the system, overall investment risk goes down!
We want to emphasize that these numerical studies are exploratory. But, we hope the modeling framework is helpful for thinking about the issues involved and generating hypotheses.
Lastly, thanks to those of you that took a look last week, and sorry it's taken me until now to do this summary thread!
• • •
Missing some Tweet in this thread? You can try to
force a refresh
As we root for everyone to make it through the extremely challenging conditions today, there's clearly a temptation in my feed to figure out what the last few days means for ERCOT's market design. Warning: I would have made this thread shorter if I had more time.
I'll preface this with the note that based on the available information, we would currently be seeing rolling blackouts no matter what design choices had been made for resource adequacy. Some more on the current situation from @gilbeaq here:
Obviously a lot of people will try to use this event as a referendum on energy-only markets vs capacity markets. Here I'm instead focusing on the question: given that we have an energy only market, how do we know it's working?
Sharing a new working paper, "Missing Incentives for Flexibility in Wholesale Electricity Markets," with a brief thread to introduce it: papers.ssrn.com/sol3/papers.cf…
Conceptually, it's pretty straightforward that greater flexibility helps systems operators manage the variability and uncertainty that accompany increasing shares of wind and solar. But it's tough to pin down exactly what flexibility is, or how markets should pay for it.
From a market efficiency standpoint, some might even question whether calls for flexibility amount to backdoor subsidies for wind and solar. In theory, time-varying prices should provide enough of an incentive for flexible resources.
Like @TKavulla, my intuition is that clean energy procurement would be better accomplished in a regional market. But I am pretty unconvinced by this flyer from NRG. A few points:
0) As a background point, it is awkward for advocates of competition to defend the PJM capacity market, which is inefficient for reasons unrelated to the MOPR.
1) The capacity market also shifts risk from Wall Street to customers, so it is weird to criticize FRR on this basis.
Okay, I'll bite. Here's three places where I think @gtpwr and @RdSweeney run afoul of economic theory in their analysis of the PJM MOPR, plus one more general though (thread, 1/).
First, it's at best incomplete to refer to resources as "uneconomic" to mean "unprofitable given the gaping market design flaw that is the lack of carbon pricing." 2/
Glen mentions that he would be open to some state policies if they don't affect the markets, but it's unclear to me what he (or the MOPR) has in mind. 3/
To make amends for my snark yesterday with some content, here's a few selections from that @ManhattanInst paper and thread that contribute to its being a candidate for retraction:
1) Would you rather have a 25% efficient panel that costs $0.40/W to produce, or a 30% efficient panel that costs $10/W to produce? This physical limit is economically (almost) meaningless.
2) The US built ~27 GW of generation last year. Multiplying that by 30 years gives 810 GW, a little short of the current installed capacity of the US (~1100 GW). This tweet is not close to correct.
I bet you all thought Energy Twitter was all out of takes. But I can't help feel that many economists who are less embedded in wholesale electricity are drawing the wrong conclusions, both from the paper and the debate it spurred. (cc'ing some: @samori8@KnittelMIT@noahqk)
To me, the key issue is that the estimates derived from the top-down regression suggest a cost of RPS that is roughly 10x what would be suggested by a bottom-up analysis. Three mechanisms (intermittency, transmission, stranded assets) are suggested to explain this.
I think why the economics crowd is missing the point is that a lot of the critiques center on things that, while important, are not core to that analysis.(learning effects, political feasibility, not including co-benefits, etc.)