Title: Electricity Markets: A Regional Perspective
Speakers: Adrienne Thompson and Chris Jones
Chris Jones (00:08):
Adrian, welcome. Thanks for joining me today to talk about the exciting world of energy markets. Now, you are currently the president of the Western chapter of the Energy Bar Association, so I thought we could start out west and give us a sense of what’s going on out there. And there’s been some interesting developments in the last few years to talk about, I think.
Adrienne Thompson (00:25):
Yeah, there sure have been. So the West outside of California is, similar to the Southeast, still relies on a bilateral market structure to buy and sell energy at wholesale. So this is distinct from a RTO or an ISO where prices are set based on nodal pricing. So that takes into consideration congestion and transmission and losses. And so that’s how generally energy is bought and sold. And I’d say about two thirds of the country are in RTOs and ISOs. And so energy markets and electricity markets in particular in the West outside of California have evolved over time. And so over time they’ve taken the form of an energy imbalance market that was started by CAISO first in 2014 and has since expanded from PacifiCorp originally to over 20 members. And so it’s quite substantial at the moment.
Chris Jones (01:23):
So the energy imbalance market, it sounds to me is a sort of a real time tool for managing supply and demand outside California, but it’s not full RTO membership. Is that right? That the full RTO structure is still very much confined to California today. Is that right?
Adrienne Thompson (01:38):
Yeah, that’s correct. So full RTO structure would transfer functional control of transmission assets over to a single entity like CAISO or the Southwest Power Pool SPP, which also has an energy imbalance market in the West. And it would also transfer a lot of the centralized planning operations that are done with each utility and that would be housed in a single entity. And so that is different than what is happening with EIM, which is really just a real time market that happens every five minutes. It optimizes lowest cost energy to serve real time need every five minutes.
Chris Jones (02:19):
So with the market handling real time imbalance every five minutes, it sounds like all the day ahead contracting and contracting for longer term power products is still done outside of California in the bilateral, what we would call the traditional bilateral market. Is that right?
Adrienne Thompson (02:34):
Yes, that’s correct.
Chris Jones (02:35):
And what are the other sort of, speaking of incrementalism, I’ve heard that there are, we’ve got the possibility of expanding that real time market into a day ahead market. Can you expand on that just a little bit?
Adrienne Thompson (02:48):
Yeah. So both CAISO and SPP are looking into expanding their energy imbalance markets into day ahead and real-time offerings. And so that would enable transmission providers and market participants to plan more fully in advance. So on a day ahead basis and then also on a real time basis. What it wouldn’t do though, it wouldn’t be a full transfer to an RTO or ISO construct in the sense that transmission providers would still be in charge of their own transmission systems. They would still be in charge of balancing their systems. And so would still have certain obligations, like according to NERC. But it would enable the footprint of CAISO and SPP to more expansively plan in a real time and day ahead basis.
Chris Jones (03:33):
So in an expanded day ahead market, the California market algorithm is gonna pick on a day ahead basis which generating plants across the west would run based on locational marginal pricing. Is that right?
Adrienne Thompson (03:45):
Yes, that’s correct. So in a sense, it would do away in that sense with the traditional bilateral construct and move towards a nodal pricing construct.
Chris Jones (03:54):
But unlike full RTO membership, it sounds like there are some pretty big components of a full RTO that an expanded day ahead doesn’t bring with it, including transmission cost allocation and you mentioned functional control. Is a day ahead offering, whether through California or SPP, are they both still considered incremental steps toward market development?
Adrienne Thompson (04:16):
Yeah, I would say so. So the transmission providers will still be, and transmission customers will still have what’s called their open access transmission rights, their OAT-based rights. And so they wouldn’t be fully moving over to an LMP based construct. So there would still be flavors of the kind of traditional structure.
Chris Jones (04:36):
And as we sit here today, both California and SPP have these day ahead market offerings. Is it fair to say that they’re vying for the affections of utilities in the West?
Adrienne Thompson (04:46):
Yes, very much. So they’re both trying to gradually bring more participants on board. And I would say a lot of transmission providers, a lot of market participants are looking to see how these different offerings develop to see which fits best for them.
Chris Jones (05:03):
And are all of these markets, these incremental markets, I’ll call them, are they all voluntary in nature? I know we’ve seen in past cases that withdrawal from an RTO once you join fully is a more difficult endeavor, but I think these markets are voluntary, right? So is it fair to say that there’s an ease of entrance and ease of exit?
Adrienne Thompson (05:25):
Yes, absolutely. It is very easy to get in and to get out. There’s no penalties involved. Similar to how it’s done in the Southeast, which has also been developing its own energy markets as I understand. Would you be able to tell me a little bit about what’s going on there?
Chris Jones (05:38):
Sure. So the Southeast energy market or SEEM, Southeast Energy Exchange Market is, similar to what you’ve described in the West, these imbalanced markets, but it’s got some fundamental differences. The Southeast has traditionally been a bilateral market for the same reasons that you talked about out West. There has been a lot of interest in maintaining local control, making sure that state commission jurisdiction is respected. And frankly, a legitimate question about whether the value proposition of a full RTO makes sense for customers in the Southeast. What you saw a few years ago was the development of this Southeast energy exchange market by Southern Company, Duke and TVA and several other regional market participants to create that more real time mechanism. Now, it’s a little bit different than what you see out west. With the energy imbalance market run by California, for example, the California market algorithm does actually dispatch units on a secure, what we call a security constrained least cost dispatch basis.
The Southeast market stops short of that. There’s no centralized dispatch in the Southeast, but there is this real time mechanism for buyers and sellers to come together, again, to manage those real time fluctuations in supply and demand that happen and gain those regional efficiencies without having to commit to a much larger regional market construct. So it still stands in stark contrast to some of the more traditional markets that we see elsewhere in the East — PJM and the New York ISO and ISO New England. And it is a little bit different from that which is going on out west. But I think both regulators, state and federal, and market participants still see the SEEM and see that as a pretty meaningful development in the history of the Southeast energy market. Now the Southeast going north up the seaboard, that’s where you get the more traditional RTO markets, the ones we’re familiar with, PJM and MISO sort of being the largest regional area.
And then you go north to New York and New England. And those markets are a little bit more tried and true these days. That’s what we would consider the full RTO, where all the utility members have transferred the functional control over their transmission system. It’s a full LMP based market so that those locational marginal prices are what sets both unit commitment day ahead and unit dispatch in the real time. And some of them have also added capacity markets. And those capacity markets have troubled state and federal regulators now for probably more than a decade. So the capacity market is a way to supplement revenue for generators when the energy market doesn’t provide sufficient revenue. But they’ve been really complicated and they’ve been really controversial for the last several years because it’s tough to get that market design quite right.
And even as we sit here in 2023, FERC has announced recently it’s gonna look into the PJM capacity market again, figure out if there’s a way to get that market design exactly right. And I’m not sure that there’s a consensus to be had there, but it’s certainly one of the most interesting areas, I think, to keep an eye on. And a lot of our clients struggle with how to invest in those markets when there is market uncertainty, both as to performance obligations. And we saw some of that with Winter Storm Elliot. PJM assessed significant penalties on some generators for performance reasons in that market. But generally you’ve also seen a struggle to get the state commissions and state regulators and all the stakeholders necessary to buy in on a capacity market design that makes sense for both the development community and sends the right price signals for new investment, but also makes sense for customers and regulators.
So it’s gonna be interesting to see how we do in that regard and where FERC decides to take it and where State Commission may decide to go as well.
Adrienne Thompson (09:31):
Yeah, certainly. And I guess the question is, is it fair to say that some of the struggles with the capacity markets in PJM and elsewhere are tied to resource adequacy in general?
Chris Jones (09:43):
I think so, right? So you’ve seen now we’ve got a pretty significant transformation going on across the country, right? We have coal units that are being retired for any number of reasons, basic economics and considerable environmental and legislative pressure in states almost across the country now. And renewables spurred by tax incentives and other government actions to encourage the development of renewables has created this historical transformation of our energy fleet. And that’s put pressure on what we call resource adequacy — making sure we have enough power plants in the ground ready to respond when we need them. Renewables for all of their benefits, both at low marginal cost and low emissions, have a problem with dispatchability. They need some sort of dispatchable units to balance them and make sure that supply and demand in real time stays constant and the lights stay on.
And so there’s a question about whether these capacity markets, which are there to provide a revenue stream to new investment in new generation, are they incentivizing the right thing or are they perhaps unduly influenced by some of these state actions or some might call them subsidies for renewable generation? It’s a difficult thing to get your head around at some point because you end up trying to decide, is this a market or is this just an administrative construct to make sure that there’s enough money there to pay new developers to put steel on the ground and give us enough capacity when we need it?
Adrienne Thompson (11:17):
Wow, interesting. So it sounds like there’s a lot happening in the West and East and energy markets generally.
Chris Jones (11:22):
I think that’s right. We’re living in interesting times. There’s gonna be a lot of new developments in the next couple of years and hopefully we’ll see folks let each region try to figure out what’s right for them. But there’s gonna be a lot of regulatory and commercial developments to keep an eye on over the next couple of years, for sure.
Adrienne Thompson (11:36):
Well, I’m really excited to see where things come.
Copyright, Troutman Pepper Locke LLP. These recorded materials are designed for educational purposes only. This video is not legal advice and does not create an attorney-client relationship. The views and opinions expressed in this podcast are solely those of the individual participants. Troutman does not make any representations or warranties, express or implied, regarding the contents of this podcast. Information on previous case results does not guarantee a similar future result. Users of this video may save and use the video only for personal or other non-commercial, educational purposes. No other use, including, without limitation, reproduction, retransmission or editing of this video may be made without the prior written permission of Troutman Pepper Locke. If you have any questions, please contact us at troutman.com.
