Abigail Krich, founder and president of Boreas Renewables, LLC, explores the innate incompatibilities between New England’s push towards clean energy and its current wholesale electricity market design.
Full video and 3 questions with Krich:
Thank you for coming. I’m very happy to have Abby Krich here today. So I’ll just read you Abby’s bio in brief. Abby is founder and president of Boreas Renewables, which is a Boston-area company. It’s a consulting firm that stands in between us as energy providers and renewable energy generators, so one of the people that actually makes renewable energy happen.
And she has a lot of practical experience. We’re looking forward to her sharing with us today. She also actively advises within the New England power pool and the New England Independent System Operator, the NE-ISO, and currently serves as vice-chair of the NE power pool Variable Resource Working Group. And variable resources are something that those of us who work in renewables think a lot about. She holds a masters of engineering and a bachelor of science and engineering, both from Cornell. So without further ado, thank you, Abby.
All right. Thanks. Thank you very much, Raf, for inviting me to speak today. Is my volume OK? Can everyone hear me? Great, OK. Good. So I’ll be talking about the New England wholesale electricity markets, and why it is that they’re basically incompatible, as I see it, with achieving the region’s long-term carbon emission reduction goals.
So the usual disclaimer– these views that I’m going to talk about today are my own. They’re no one else’s. They’re not my clients’. They’re just my observations that I’ve seen from working in the field.
Also, another disclaimer that I like to start with when I talk about the energy markets– they’re a bit complex. We’re going to pretend we’re in a frictionless vacuum here. I’m going to simplify things, just to try to focus in on some key ideas that I want to talk about today.
So what I’ll start with– I’ll start by talking about the wholesale electricity markets in general. What are they? And then I’ll talk about policy requirements that we have in the region to decarbonize. And then I’ll talk through some things related to the energy market, and then the capacity market.
So wholesale electricity markets– the areas in this figure that you can see that are shaded, they are each a wholesale electricity market. So in general, in each of these markets, there are regulated utilities that own the wire. So here, for example, that would be Eversource.
There are, then, generators that are independently owned by independent companies. And those generators– those independent companies– compete in the wholesale electricity marketplace without any centralized planning. So instead of centralized planning, the market itself sends a signal to indicate when and where to build or retire power plants, and when those power plants that are built should either run, at what levels, or when they should sit idle.
And so the market is run by an independent entity that has no ownership interest in any particular part of the market, called an independent system operator. And in New England, this is called the independent system operator of New England. And just for reference, the gray areas on this map are the areas that are still vertically integrated and don’t have these competitive marketplaces. But for today, we’re going to focus on that green market in the upper right, the New England wholesale electricity market.
So for some background– some context– on the ISO New England, the market size is about 121,000 gigawatt hours of energy per year, last year. And it’s made up of– about 85% of that is supplied by generators located within New England. 43% or so of the total comes from fossil generation, but 42% of the total comes from either low- or no-carbon generation resources.
And then a little over 16% comes from imports from neighboring regions, so either from New York, New Brunswick, or the majority from Quebec to the north. There’s also– we have quite a bit of pumped-storage hydro in New England. So when they’re pumping water up the hill so that they can then provide energy later, that uses energy, and so that’s added on here.
You’ll notice that, until you add that minus 1.4% for the pumped-storage hydro pumping load, were over 100%. So all of that energy is supplied by a fleet of generators that is about 35,000 megawatts in nameplate capability. So that gives you some background on the size of the market overall and its makeup.
Now, the market in New England has seen some fairly significant emissions reductions over the past 15, 20 years. In 2000, ISO New England market coal and oil provided 40% of the energy in New England. Natural gas, on the other hand, there wasn’t very much of it. Natural gas generation, it only produced 15% of the energy in New England.
Fast forward to 2016, and coal and oil are down to 3% in that year, and natural gas is up to 49%– so a huge transformation in that time. And because of that, air emissions dropped pretty significantly. So the figure that you see to the right, the green shows the carbon dioxide emissions in 2001– it’s slightly different years. Carbon dioxide emissions in 2001 dropped to the blue bar in 2016. So a fairly sizable drop in carbon emissions going from the coal and oil over to natural gas.
So that’s good. That’s a good start. But it’s not enough. We have 32 years left to decarbonize our electricity system in Massachusetts. So Massachusetts has the Global Warming Solutions Act, which requires– it’s not an aspirational goal. It requires greenhouse gas emissions from each sector of the Massachusetts economy, not just the electricity sector, to be 25% below 1990 levels by 2020.
We’re in good shape, based on what I showed on the last slide. We’re in good shape to meet that target. That’s not terribly concerning right now. But then, in 2050, we have to be at least 80% below 1990 emissions levels. So how do we get there? That’s a very sizable emissions reduction.
We basically need to have a fully decarbonized or near-fully decarbonized electricity sector by 2050. And it’s also going to be a much larger electricity sector, because in order to get to that 80%, we need to largely electrify the transportation and heating in Massachusetts, as well. So a much larger electricity market– almost no emissions can come from it, if we’re going to meet this requirement.
And actually, it’s not just Massachusetts. It’s New England as a whole. So every state in New England has a similar emissions reduction target. So the dark gray are our legislatively binding mandates. The light gray are targets that don’t have the same binding nature. But we’re going in this direction, right? All of New England has similar targets for massive emissions reductions, around 80% from 1990 levels, by 2050.
So 32 years sounds like a lot of time– plenty of time. We just need to deal with the system now– the market and reliability now, and we’ll figure out how to decarbonize in the future. We’ll get there. Actually, in the electric world, 32 years is not actually that much time.
So in 2010, ISO New England– the grid operator here, the market operator– they did a study. They looked at which generators on the system were coal- and oil-fired generators on the system were at risk for retiring. They wanted to know, what risks do we face in this market?
And they found that there are about 8,000 megawatts of coal- and oil-fired generation at risk of retiring because of their age, because of economic trends. And those plants, at the time, were between 32 and 58 years old. So these are long-lasting assets. If you invest in a gas plant, or a pipeline, or infrastructure related to them today, the expectation is that it will be around for 30, 50, 70 years from now. So if we have to decarbonize by 2050, I think that raises a question about whether we should be building more fossil fuel infrastructure today.
So just for a sense of what’s happening on the system, from 2013 to 2021, about 3,600 megawatts of that at-risk generation has either retired or committed to retiring by 2021. And in addition, about 1,300 megawatts of nuclear has either retired or committed to retire. So altogether, that’s about 10% of the New England generation fleet. There’s a big turnover happening already, and a big opportunity to be replacing these outgoing resources with clean energy sources.
But when I look at the current markets, that’s not what the current markets are doing. That’s not what the current markets are driving us towards. And that’s what I’ll be talking about.
And so I said previously, we’ve seen a big growth in gas-fired electricity production and emissions reduction, but I said that that doesn’t make sense to keep doing. Why not? It’s not going to get us to that 80% emission reduction goal. So the 2016 ISO New England emissions rates are shown here. You can look at it. You can cut the data a couple different ways.
The average emissions were 710 pounds of carbon dioxide per megawatt hour of electric energy produced. That was the average across the year. If you look at the average of just the marginal generating units– and I’ll explain in a few minutes what a marginal generating unit is– it was about 842 pounds per megawatt hour. So that’s our benchmark for where we are today, in terms of emissions rates.
Then you look at emissions rates for new, efficient, natural-gas-fired power plants. So the last one to reach commercial operation in New England was the Kleen combined cycle plant in Connecticut. And its emissions rate reported in 2016 was 850 pounds per megawatt hour. So that’s not really lowering our average emissions by adding a plant like that.
Footprint Power combined cycle plant in Salem, Massachusetts– it’s under construction now. As I understand it, it’s basically the most efficient combined cycle plant out there. Its projected emissions rate, depending on how it operates exactly, is about 835 pounds per megawatt hour.
So it’s a little bit lower, but again, this isn’t getting us to 80% emissions reductions, right? There’s diminishing returns at this point, where we are, to adding more gas to the system. So really, if we’re going to meet these emissions reductions requirements, we need to reduce demand for electricity, and we need to transition to producing more– or actually, eventually nearly all of our electricity– with low- or no-carbon resources.
So let’s talk about that. So energy efficiency– that’s the first stop– reducing the total demand on the system. So New England states are very aggressive on this, and they spend over $1 billion a year on energy efficiency measures.
I don’t know if any of you own your home or rent a home, and if you haven’t had your Mass Save Energy Audit yet, I highly recommend it. They’ll give you free light bulbs. They’ll help you insulate your house. That’s all part of these energy efficiency programs.
And the result of them is what we see here. So the gold trend line that you see there– the solid gold is the gross total demand for electricity in New England, starting in 1990, going up to present. And it’s been climbing.
And then the projected demand over the next 10 years continues to climb, but that’s gross. If you take that gross demand, and then you subtract out the impact of all of the rooftop, behind-the-meter solar that’s being installed, and then you subtract out from that all of the energy efficiency– so the impact of all of those LED light bulbs and things like that that people are installing– you actually get to that blue line. That’s the net energy that actually is what needs to get served by the generation and the imports.
And that blue line– be careful– the axis doesn’t start at zero, in terms of scale. But that blue line is quite a bit below the gold line, and most importantly, it’s trending downwards. So the amount of energy that we are expecting to need over the next 10 years is actually going down. In terms of decarbonizing, that’s the right direction, although I expect it will have to go back up once we start really, seriously electrifying transportation and heating.
OK, so energy efficiency– we’re going in the right direction there. I described, in terms of the generation in New England, how much energy comes from different fuel sources, but what do the actual generators look like that are producing them, because they don’t all produce the same amount of energy? So 68% of our generator fleet in New England is fossil-fuel-fired– vast majority. 76% of that is either gas or dual-fuel that can burn gas or oil.
So if the remaining coal and oil is replaced with all gas, which is what the market is really driving towards, that will barely help with emissions targets. Instead, what we need to do is build clean generation. So what we see on the left-hand side, the left-hand bar is the existing generation fleet in New England, and the bottom of that is the fossils– so that the black, brown is the coal, oil, then you have the gas and the dual-fuel. That’s our fossil component of our generation fleet.
The right bar shows the generation that is in what’s called the interconnection queue. They’ve submitted applications to connect power plants that people are trying to develop to the transmission system. So when you look at those applications, a good chunk of it is still fossil-fueled. It’s still natural gas. But then a very large part of it is solar– is the yellow. Green is wind. So there’s a lot of projects under development that people want to build a New England if the conditions are right to actually build them.
So what kind of growth have we seen in wind and solar so far, and what do we expect coming up? We have about 1,350 megawatts– just a little more than that– of onshore wind operating in New England today. That’s up from about 375 megawatts in 2011– so quite a bit of growth. Not dramatic, not as fast as I think I had hoped we would be growing, but quite a bit of growth in wind in New England.
But we have over 8 gigawatts of wind in the interconnection queue right now, so we could be installing massive amounts more if the conditions were right– if the market were signaling it. We have 30 megawatts of offshore wind operating off of Rhode Island. It’s actually the first offshore wind project operating, I believe, in the Western Hemisphere. So go us– that’s great.
It’s a small project, but there’s Massachusetts legislation that requires the solicitation of 1,600 megawatts of offshore wind by 2027. And the first of those projects, we’re actually expecting the selection of that project and their contract to start negotiations in a few weeks. So things are moving on offshore wind.
And then solar has grown really dramatically in the last few years. So we have about 2,390 megawatts of solar operating and installed in New England, up from about 250 megawatts in 2012. So that’s this figure to the right, showing the solid trend lines– what we’ve seen since 2012.
And ISO now forecasts every year, based on existing policies that are driving the solar development, how much solar we expect to see over the next 10 years. So that’s the dashed line that you see to the right. And we’re expecting the solar to grow up to 5,750 megawatts by 2027– so quite a large growth in solar that we’re seeing here.
Even so, with what we have today, the wind and solar that’s installed is producing enough energy to be equivalent to about 6% of the load in New England. So it’s not nothing, but it’s not a huge portion of the generation yet. Now, if all that offshore wind and PV that I talked about is built, that gets our total up to about 10%– so going in the right direction, but again, not going to get us 80% carbon reductions.
If all 8 gigawatts of onshore wind gets built– which would be a lot for New England, but that is the direction we need to go– and if all 8 gigawatts of onshore wind is added, that gets our total up to about 30% from wind and solar. So if that displaces all fossil generation, it still leaves 19% of our load being supplied by fossil generation. So we still need more than that. That’s not enough.
So then you start looking at other options. There’s hydro from Canada. So there’s Massachusetts legislation for that, as well. So Massachusetts legislation calls for the procurement of about 9,450 gigawatt hours per year of clean energy– and they consider hydro imports from Canada to fit that definition, by 2022. So that’s a little over 1,000 megawatts steady throughout the year.
A transmission project to import that amount of hydro energy from Quebec into New England has just been selected and is negotiating its long-term contract right now. That would be enough for about 8% of New England load. So that’s a really big deal. That is one big project for New England. And if it displaces fossil generation instead of displacing other clean generation, then that still leaves 11% of our load coming from fossil. So still, we need more.
So we have a great start here. We’re chipping away at things, but it’s still just the beginning. And these numbers that I’m saying– they’re assuming this 8 gigawatts of onshore wind actually gets built, and there is no clear path forward for that to happen right now. So those are all projects that could be built, but there’s no path for them right now.
And as I said, electric load is going to rise with electrification of the other sectors, so we actually need more than these numbers here. So what I’m trying to paint a picture for you is that we need to have a massive fleet changeover in the next three decades. We need to retire and probably stop building new fossil fuel power plants, and we need to bring on a huge amount of no- and low-carbon energy resources.
So what we’ve seen so far is that contracts and regulated rates, and not the wholesale electricity markets, have been driving this growth in clean energy development that we’ve seen and that we’re expecting in the coming years. I’m not aware of a single wind or solar project that has been built in New England without a long-term contract or a regulated rate supporting that project. I don’t know a single project that has looked at the wholesale electricity market and said, yeah, I’ll invest my money in this, and I’ll see if I make my money back. That’s not what’s happening.
I would prefer to see the electricity markets– I like markets. I like the electricity market. I would prefer to see them driving this transition, but it’s unfortunately just not– this, what I’ve described, is not what they’re designed to do. So it won’t send the price signal for the entry of these clean energy resources. It’s actually sending counterproductive signals, saying that we need to be building more gas.
And yet, our policy requires that we decarbonize. So the growth of these clean energy resources has to keep continuing. Whether the market is doing it or not, it has to keep continuing to meet our public policy requirements. So something’s not matching up here.
This is actually a dominant discussion at ISO New England and nationally, in how markets and public policies interact with each other, and how the markets can– the catch phrases are– either accommodate or achieve public policy goals, or whether they should do either of those things. And either we figure this out or, I’d say, the markets will be gone in under 32 years, because something’s not matching up.
So now I’m going to transition, now that I’ve given that background, to talking about the electricity markets and why it is that I say that they’re not working for these clean energy resources and this transition. So there are three key components to the wholesale electricity markets. There’s an energy market, which, in 2016, was a little over $4 billion in New England. And that’s the price that gets paid for actual electric energy that gets produced, so dollars per megawatt hour of energy produced.
There is a much smaller reserves market, which is about $0.1 billion in that same year, which is the price paid for the ability to produce energy in a short amount of time– so talking 10 minutes, 30 minutes– in case there is a contingency on the system. If we lose a power plant, if we lose a tie-line to a neighboring market, these power plants or these resources are able to step in very quickly to make up that power. They’re the backup supply that’s available. So they’re paid to just sit there and be available.
And then there’s the capacity market. So the capacity market fluctuates pretty significantly, but in 2016, it was a $1.2 billion market. So the capacity market pays a price for a commitment the resources make to be able to be available to provide energy and reserves multiple years into the future. So it’s not paying for the actual energy production. It’s just paying for the commitment that your resource will be available to produce energy to meet demand in the future, to make sure that we have enough resources to keep the lights on, to meet our peak demand.
So the intent of the wholesale electricity market and all of these different pieces of it is to use competition to procure and operate the most economically efficient resource mix that we can, subject to maintaining reliability. So I’ll gloss over the reliability piece, but all of this is always subject to reliability and actually keeping the lights on.
And then some background on economics of fossil generation versus carbon-free generation– in general, a new natural-gas-fired generator is– this is all relative here– but inexpensive to build. It has low capital costs, but it is expensive to run. It has to pay for its fuel, so it has a high cost to operate and produce energy. In comparison– flip that– new carbon-free resources are higher cost to build– higher capital costs– but generally, they are low costs to run, or even free to run, because they don’t generally have to buy their fuel.
Now, let’s look at the energy market and energy market pricing. So the way this works, it’s a competitive market. Each supplier that wants to offer energy into the market offers its variable cost of producing energy. So it’s fixed its capital costs to just be available on the system. They don’t get to offer that into energy market. They’re just offering their variable costs of producing the next megawatt hour.
If their fuel is free– if they’re a wind plant, for example– then they basically have no variable cost. They would offer a price of zero. If they’re receiving, maybe, a production tax credit that pays them a tax credit for each megawatt hour that they produce, then maybe their marginal variable cost of producing electricity is actually negative, because they’re getting paid something from something other than the energy market.
So the ISO New England auction for energy will take all of these offers that had come in from all of the different suppliers and select how much energy each different supplier should produce, based on their offer costs. So they’ll take the lowest price offers first. They’ll line them all up and take the lowest price offers first, until they have chosen enough energy supply to meet the demand. And then the– subject to physical and reliability constraints– and then the last offer accepted, that sets the clearing price for the auction.
So this process is called economic dispatch. And it’s a uniform clearing price auction, because that last offer accepted sets the price that all of the accepted offers get paid. So even if you offer zero into the market, if a natural gas plant sets the price at $50 per megawatt hour, you’ll get paid $50 per megawatt hour.
So I’d like to walk through a very simplified example of an energy action, to show you some things that happen in it. So let’s imagine now that we have two generators in our system. So we have generator A and generator B. They’re the only generators on our system. And we have 100 megawatt hours of load in a given hour.
So generator A is offering 50 megawatt hours at $100 a megawatt hour. It’s a fairly expensive generator. Generator B is a little less expensive. It’s offering 70 megawatt hours at $80 per megawatt hour. So we have 100 megawatt hours of load.
We take the lowest cost offer first, so generator A is selected for– sorry. So all 70 megawatt hours of the less expensive generator B get selected, and then only 30 of the more expensive generator A get selected. And because generator is the last offer accepted, it sets the price for both of them at $100 per megawatt hour. So that’s how the market has historically worked in the past, except with hundreds of offers, instead of two.
So let’s look at costs and profits here. So let’s look at the production costs first. Based on the megawatt hours that were selected and the price that each of them offered, which would have been their variable production cost, generator A had a cost of $3,000. Generator B had a cost of $5,600.
Now, what did they get paid by the market? So the market clearing price was $100. So generator A gets paid $3,000, and generator B gets paid $7,000 from the market, which means that generator A made zero profit.
So it set the price at its cost. It breaks even, but it doesn’t make any profit. It was what’s called the marginal generator, the marginal unit. Generator B, on the other hand, it makes $1,400 in profits, because it was inframarginal. It was below the marginal price.
So now let’s add a third generator, a clean energy resource with free fuel that’s offering $0 per megawatt hour into the market. So we’ll stack our offers up in low to high price order. And now let’s imagine that we have 40 megawatt hours being offered by this clean energy resource. The market only needs 60 megawatt hours from what’s now the more expensive generator, B, which is less than the prior example, and we don’t need any energy from generator A. So now generator B has become the marginal unit, and it’s setting the price at $80 per megawatt hour.
So again, let’s look at costs and revenues here. So generator A went from being the marginal unit and earning no profits to not running at all, being out of merit, and also earning no profits. So it’s indifferent to the situation.
Generator B went from being inframarginal and earning $1,400 of profits to now being marginal and earning $0 in profits. So it’s not particularly happy with the situation. Generator C, our new clean energy resource, it’s inframarginal, and it earns $3,200 in profits, because there was a big difference between its costs and the clearing price in the energy market.
So with low levels of renewables in the market, like what we have today, what we’ve seen so far, these renewable generators that come into the market can earn very large profits in the energy market to pay for their fixed costs to build these projects. But then what happens as we keep building more and more wind and solar, and bring in hydro, and have our nuclear plants running?
Let’s imagine in this example that we add another 70 megawatt hours of zero-cost fuel supply of clean energy resources. So now we have 110 megawatt hours being offered of clean resources offering at a price of zero, but the market only needs 100. So nobody earns any profits in this energy market. The market price gets set at $0, because the clean resources are marginal.
These clean energy resources, C and D, they’re not losing money, but they’re not making any money, either. They’re not earning any profits that they can use to pay off their fixed costs of actually building their project. So they’re not particularly happy with this situation.
And then, in a clean energy future, what do the energy market profits look like? So today, natural gas is marginal and sets the price in the energy market about 80% of the time. So almost all the time, natural gas is setting the price for everyone. This chart on the right that you see shows– in green, it shows the natural gas price, and in blue, it shows the wholesale electricity market price, and they’re almost right on top of each other. So natural gas, which is quite volatile in price, is driving the cost of energy.
The more fossil fuel resources we add to the system, the more often they’re going to be setting the marginal price in the market at $0, or maybe even at negative prices. So if solar is marginal when it’s sunny, if wind is marginal when it’s windy, if nuclear is marginal in the middle of the night, there’s very little money left in the energy market, and possibly no money left in the energy market, and no profits for anyone in the energy market if you take this far enough, which is where we need to take it to meet the legislative requirements.
So if there’s no money in the energy market anymore, how do you pay for new power plants? How do you finance power plants? How do you keep existing power plants going? And if there’s no money in the energy market, what’s your incentive to actually produce energy? What’s your incentive to do your preventive maintenance on your system, to actually run when you’re called on, to staff your plant appropriately? If there’s no money to be made, that’s a question for another day, but that is an issue.
So I want to focus on the question of how do you finance your power plant, if there’s no money in the energy market anymore, because the marginal cost keeps getting set at zero. So that brings us to the capacity market. So in New England, we have what’s called a forward capacity market, FCM for short. And the FCM procures resources with sufficient capability to meet the forecasted peak demand for energy and reserves about three years into the future. So this is a market that makes sure we have enough resources available in the future to meet demand in the future.
Like the energy market, it’s a uniform clearing price auction, and the forward capacity auction happens once a year. So new resources that come into this auction, they offer their price that they need in the capacity market in order to be built, and then they can actually lock in that price that they get in that first year. They can lock that price in for seven years, if they want– up to seven years.
And the whole point of this market, and the whole point of that seven-year price lock, is that that is a financeable market commitment. So that is enough revenue that they can go to a bank. They can go to a lender and get financing to actually build their generator. That’s the point of this market.
Existing resources come into this market as price takers. They just take whatever the price is each year, and that’s enough– that’s supposed to be enough– to cover their fixed costs of keeping their generator up and running. But if it’s not, then they might withdraw their offer and what’s called de-listing from the market. So if the market price is too low, and it’s not covering their fixed costs, then they would de-list and withdraw their offer capacity from the market, and either mothball their plant for a while or retire it completely.
So this market is really intended to drive those investment decisions in building new plants or deciding when it’s time to retire existing plants. It’s meant to provide the missing money to cover those fixed costs that aren’t covered by the energy and ancillary services markets. But again, like I’ve been saying, the price signal from this capacity market, which is really what’s supposed to be driving these investment decisions and determines what our fleet is supposed to look like in the future, it is driving us towards building more gas, not building more clean energy resources.
And there are multiple aspects of the FCM design that are causing this, and they’re working against the very policy requirements that we have to decarbonize our system. So I’ll talk about a few of those aspects of this market and why they’re fighting these public policies– or how they are. So the first is that the capacity market, it’s really complex, it’s very risky, and it’s getting more so every year. And that’s why I have a job, so in one sense, that’s nice. But that’s not what I’m in this for.
So it’s very complex. It’s very risky. For a large generator, it’s fine. They can invest in figuring out how this market works and figuring out how to manage the risk in the market. But if you are very small distributed generator, the cost-benefit of trying to deal with this market, versus just forgoing that revenue, it’s not obvious that it’s worth it to even bother to participate in the market if you’re too small.
And so there’s actually a significant build-out happening just outside of the capacity market. So this figure over here shows ISO New England’s projection, again, of the solar build-out that’s expected to happen over the next 10 years, cumulative. So the orange bars there, that’s your rooftop solar in New England. So that’s your behind-the-meter solar.
And it’s actually– what it’s doing, it’s reducing demand, like I talked about earlier. And that reduced demand is reducing the amount of capacity that the capacity market needs to purchase. So it’s getting recognized in the market that way, without actively participating in the market.
The gray bars on the bottom– if you can squint and see them– those are the solar projects that are actually participating in the capacity market that are offering, and getting commitments, and supplying their capacity towards the need that we have in New England. The green bars between the two, that’s the solar that is completely ignored by the capacity market. It’s neither reducing load and reducing the amount of capacity we need to buy, nor is it actually actively participating in the market and getting recognized by the market.
So by 2026, ISO New England projects that there will be 1,250 megawatts of solar– that’s AC nameplate– built in New England that is completely outside of the capacity market. And when we look at the capacity value of that, that’s equivalent to 500 megawatts of capacity market value, because solar doesn’t produce at full output all the time. 500 megawatts, that’s a large gas plant.
So that’s a large gas plant that the market is going to say we need to build to meet our demand for capacity, or that’s a large gas plant that is going to want to retire that the market is going to say, we can’t let it retire, because we still need it, even though, actually, we have the solar there. It’s just being ignored by the market. So that’s a tricky one to figure out, but it’s a reality of what’s happening.
I get a lot of solar projects that want me to help them with the capacity market, and the first thing I say is, how big are you? And most of the time, the answer has been, it’s not worth it. Sometimes, if they’re big enough, it is. And more and more, these projects are getting bigger, so more of them are getting in, but it’s still not clear that it makes sense for most of them.
So that’s a byproduct of just– the market’s complicated and risky. But then there are some actual, fundamental market design features that are intended to keep clean energy resources out of the market. So one of them is called the minimum offer price rule, MOPR for short. And so as this gets a little bit wonky and into the weeds, but I’ll try to explain what it’s there for and what it does.
So because the FCM is so important for driving these investment decisions and maintaining resource adequacy in the region, the market has been protected from what’s called buyer-side market power that could cause price suppression in the market. So if you imagine a buyer in the market subsidized some otherwise uneconomic resource that wouldn’t have cleared in the capacity auction, but with this subsidy is able to offer a lower price and bring the whole capacity auction clearing price down, then that could lower the capacity auction clearing price that gets paid to everyone. And so if you’re a big buyer, maybe it’s worth it to subsidize a few small uneconomic resources and bring the price down, so you save money on all of the other– the market’s 35,000 megawatts, roughly, so if you subsidize a few to save on the other 35,000 megawatts, maybe that’s worth it for you as a buyer.
But then the market price that’s being sent out to the market by the capacity market wouldn’t actually be the competitive price to build a new power plant without these subsidies. So there are questions about whether you can actually finance competitive projects if they’re competing against these subsidized projects, and that’s a concern. So the MOPR was created to prevent that type of action in the market.
Can you just give an example– who would be a buyer in this case?
So the classic example– they’re not directly the buyer, but they might be acting on behalf of buyers– would be states. So a state that decides that they are going to provide subsidies for– OK, so there were some cases where there were some states that thought they could lower the capacity price by subsidizing some new gas plants. And so they provided subsidies for some new gas plant that then came into the market and brought the price down.
This is in another market. And the regulator stepped back and said– the federal regulator– said, wait, wait, wait, wait, wait. You can’t do that. That’s not fair. So they said, you can’t do that. You can’t subsidize a couple gas plants in order to bring the price down for everyone. We’re going to prevent you from doing that.
So the state wasn’t directly the buyer, but they were acting on behalf of all the people who lived in the state, who were the end users. So the federal regulator said, no, no, no, no, no, you can’t do that. We’re going to create this MOPR, this minimum offer price rule. And what the MOPR is going to do is it’s going to set a minimum price that every new resource coming into the capacity market can offer in the auction.
And the MOPR– the example I just gave– this all came up because of subsidizing fossil fuel plants, actually, but it doesn’t differentiate between subsidies that are provided for the purpose of suppressing the market price, versus subsidies that are put in place for what’s referred to as legitimate public policy reasons, like decarbonization. It lumps them all together.
So how do we do this? So ISO New England, they periodically calculate what they call an offer review trigger price, ORTP, and that is their estimation of the minimum unsubsidized price that resources of a different technology type would need from the capacity market in order to break even and make those projects financeable. So it’s meant to be the minimum that these projects would need in the capacity market to make their projects work.
And it importantly excludes any out-of-market revenue they’re getting. So if they’re getting any– it’s called out-of-market revenue– any of these subsidies outside of the market from, maybe, a contract that’s above market prices or, for example, solar in Massachusetts that gets special incentives for solar located in Massachusetts that not everyone gets, those revenues get ignored in this calculation, and they come up with what they think a resource that’s not getting those subsidies would need from the capacity market. And that becomes the ORTP.
And so the ORTPs were calculated for the most recent time in 2016 for the twelfth forward capacity auction. And that’s what’s shown on this table here. So natural gas combined cycle plant, for that auction, they determined should need $7.86 from the capacity market to break even, basically, given all of the costs that they assumed and the revenues that they were expecting from other parts of the market.
A simple cycle gas plant was expected to need $6.50 from the capacity market. Wind was expected to need about $11. Solar was expected to need about $26. Now, everyone can nitpick whether these numbers were calculated correctly, but these were the numbers that were calculated. So let’s talk about what they do in the market, and what they mean.
So even if you have a new resource that’s viable and can be built below those ORTP prices, they’re not allowed. The minimum offer price rule says that they’re not allowed to offer a lower price into the market. Once the market price gets to that level, their offer just gets kicked out of the auction.
If there’s a project that’s viable because of out-of-market revenues, they don’t get to offer below their ORTP. That is their floor price. So that means that the capacity market– what it’s going to do is it’s going to procure the least-cost resources that it sees in the action.
So it’ll procure the lower-cost new resources like gas plants first. We see their ORTPs of $6, $7. It’ll procure those first. It will only procure those higher-cost resources that have that minimum offer price of $11 or higher– it will only procure those if there aren’t enough lower-cost resources. If there aren’t enough gas plants being offered to meet the demand in the market– to meet the requirement in the market– that’s the only reason that it would clear at a higher price and accept those resources.
So that leads to over-procurement, because those resources are getting built anyway for policy reasons, so then you’re building capacity outside of the market and more capacity from the market. And it’s building the very resources that the policies are trying to replace. So there are some accommodations in the market for public policy, to try to bring these resources in. So there used to be what’s called a Renewable Technology Resource Exemption, which let up to 200 megawatts of clean renewable resources into the market each year they could offer at any price that they wanted.
But that has just been eliminated. It is now phasing out, and is being replaced by a market mechanism called CASPR that creates a secondary substitution auction that’s meant to match up resources that want to exit the market and retire with these new resources that want to come in. And then they’ll go into this secondary action, and they’ll match up with each other, and the existing resources will leave. The new resources will come in, and everyone would be happy.
Except this market that’s been created– the auction will happen next year for the first time– this CASPR auction is extremely illiquid, the way it’s been designed, and I’m skeptical that many, if any, new clean energy resources will actually be able to come into the market through this auction. So we’ve set up this very complicated auction that I don’t think is actually going to allow clean resources into the capacity market. So again, they’re going to get built and just operate outside of the market, completely ignored by the market. And the market is going to keep procuring enough resources to supply the need.
So the costs have been coming down, right? So wind is becoming more cost-competitive. Solar– prices have been coming down. So what happens if a project can actually show that it’s viable in the marketplace, that it’s cost-competitive, even without subsidies outside of the market?
So those projects are cost-competitive. That’s actually been the case, oftentimes, in recent years, for onshore wind projects that don’t need major new transmission built. Solar has been inching closer to that each year. It’s still not there, but it is trending in that direction.
So those resources, if they offer into the auction and clear, just like a gas plant, they can lock in that first year’s auction price for seven years, which is meant to make them financeable, and then they float with the market. But unlike a gas plant, that’s still not enough. So even though these projects are completely cost-effective in the market– cost-competitive, when you look at the big picture– you still can’t finance them from the market.
So here’s why. So a gas plant in the capacity market, at the break-even capacity price, the ORTP value that was calculated, if it locks that price in for the first seven years, what this shows on the bottom– so that gas plant will recover about two thirds of its capital costs from the capacity market– from that locked-in revenue that it knows it’s going to get for the first seven years.
So only a third of its capital costs need to be recovered from revenue sources that are subject to market price volatility or regulatory risk– so the energy market, ancillary services market, or the capacity market after year seven. So two thirds of the revenue locked in– sorry, of their capital costs locked in. They can go to the bank with that and get financing.
Wind and solar, on the other hand, even if the market were to clear at their break-even cost– so they’re cost-effective at that point– they’re only earning 10% to 16% of their capital costs from the capacity market that are locked in. I can’t go to the bank and say, I know I’m going to be able to pay you back 10% of this. Will you lend me the money? That’s not going to fly.
So even though these resources are becoming more and more cost-effective, even though some of them are completely cost-effective and competitive now, and may even be the low-cost resource, they still need a contract. They still need a contract outside of the market, because the market isn’t giving them what they need to actually get the loan to finance and build their new clean energy resource. They’re not necessarily more expensive, but they don’t have any market certainty from the market the way that a gas plant does, or the way a gas plant could.
And then let’s take it a step further now. So I talked earlier about what happens if we get to that 80% reduction in carbon emissions, and there’s no profits left in the energy market. These resources are making most of their money in the energy market today. So what happens if there are no profits in the energy market?
So these zero-fuel-cost resources, the price disparity in the capacity market gets even larger, because they have no revenue left in the energy market. So they need to get all of their costs paid for by the capacity market. So if you take that same financial model that ISO used to create the ORTPs, and you zero-out the energy market revenues, and leave everything else untouched, you come up with what’s shown here.
So the simple cycle gas plant with energy market revenues that are expected– the ORTP was $6.50. If we assume no energy market revenues whatsoever, they only need $6.75. They’re not really depending on the energy market to finance that project. It’s the capacity market, and so it doesn’t change very much.
But the wind and solar– wind goes from $11 to $55. Solar goes from $26 up to $68. So now, if you imagine a capacity auction like this in the future, where you have gas plants being offered at $6 and wind being offered at $55, the market’s not going to buy the wind. It’s going to buy the gas.
So people talk about carbon pricing. If we just had carbon pricing, it would fix this problem. And it– maybe temporarily. Maybe temporarily. For a few years, it’ll fix the problem. So you put a price on carbon, the fossil plants, they have a higher cost now to operate. When they’re marginal, it raises the energy market price, and so the clean energy resources make more money when they operate, because the price for energy is higher.
But it’s only temporary. What happens when those clean energy resources that don’t have a cost for carbon emissions– when they start setting the marginal price for energy, the carbon price doesn’t do anything for them, and we still end up with zero price for energy. So carbon pricing, maybe it’s a temporary fix. Maybe it’s a temporary Band-Aid, but it doesn’t solve what I’m talking about here.
There are a lot of other ideas for achieving public policy requirements through the markets. So one option is recognizing the actual policy requirements as explicit constraints in the auction. So you take this clearing algorithm that’s been written for the auction, and you put in as a hard constraint that it needs to purchase a fixed amount of clean energy resources, or no more than a certain amount of fossil resources. The market can clear against that constraint, and it will procure the right mix of resources to meet that requirement.
But who determines what that requirement is? We have a six-state market here. So there’s a California market, there’s a New York market. Those states get to decide their requirements, and maybe they can put them into their markets.
But here, we have six states sharing one market. Which state’s policy goes into the market? How do you reconcile who pays for any increased costs or savings that might occur, based on trying to implement policy through the markets? The states do not see eye-to-eye on this.
It also raises states’ rights issues. So the ISO New England market is a federally regulated market. I don’t know if anyone here thinks the states are ready to cede implementation of their public policies to the federal government. I don’t think they’re yet. So we hit a roadblock there.
So wrapping up, the energy market has less and less money in it as we really move towards decarbonization, which is what we need to do. And even if it did have more money in it, it’s too volatile to provide financing, anyway, for new clean energy resources. The capacity market is and will continue ignoring many, or even most, clean energy resources that are built for policy reasons. So we’ll be building redundant systems, which doesn’t make sense.
It doesn’t provide a financeable revenue stream for these clean energy resources. Even if they’re cost-effective, and even if it’s clearing at the price that they need to break even, it’s still not financeable. And the more clean energy we add to the system, the more the market will drive us towards the very fossil resources that we’re trying to replace with these policies.
But yet, the policies do require more clean energy and less fossil energy. So that forces the states to achieve their policies outside of the markets, as they’ve been doing through contracts, and regulated rates, incentives. And those, in turn, distort the markets. So then the markets get changed to protect themselves against and correct for the impact of those policies on the markets and the price suppression, and that’s where we are.
And it sort of works today. Some accommodation may work in the market temporarily, but if the policy resources get too large compared to what’s left in the competitive marketplace, there’s not much of a market left there to protect. So as I started, I like the idea of markets. But as I see it, this market system that we have, it’s just not going to work much longer, the way we’ve designed them. So it will work for some number of years more, but at some point between now and 2050, it’s not working anymore.
And so there are a lot of people who think– for whatever reason, they’re not sure if this transition is happening. And if you’ve ever been able to see Gina McCarthy, the former EPA administrator, talk, she has this phrase that I like. She says “the clean energy train has left the station.” There’s no question about it. It is happening. We are on this path, and get with the program.
So if we’re going to have markets that last, and there are a lot of people who work in the markets who want to see them last, my message is that we need to figure this out. So I don’t know what the solution is. There are a lot of bright people here at MIT who are working on questions like this. And if you have ideas, fantastic. Work on them, develop them, and maybe they’ll solve this problem.
All right. Thank you, Abby. That was great– really walking us through the real-world implications of some very– at least to a boffin like me– arcane market– the fact that– we have time for a number of questions, so I saw– maybe back there was the first visible hand to me. I’m staring into the light, so if I miss you, wave.
Yes, I’m wondering if you’ve done the thought experiment or even analysis of the implications of low-cost energy storage. Does that ameliorate or exacerbate the problem?
I haven’t. So energy storage will tend to even-out the market– so even-out that volatility and those fluctuations. But it’s not going to solve– when there’s no money left in the energy market, adding storage won’t create energy profits. So I don’t think it solves the problems that I’m describing. It does help with a lot of other issues, but not this one.
Does ISO New England either understand or agree with what you’re saying, and if so, might they be motivated to change the rules? And if they don’t agree, what would you say is the reason for that? Are their political or economic interests militating toward their not understanding or agreeing?
I think there are a lot of people there who understand this. Whether they agree with it, I can’t speak for them. I don’t know. I think the status quo is hard to change. I think there’s a constant process of incremental changes to the market being made, but I think something fundamental might be needed.
And that’s a hard change to make from inside the system. Their number-one priority– so they operate the system as efficiently as they can economically, always subject to reliability. So their primary interest is in keeping the lights on, and operating a system that’s decarbonized is something people haven’t done.
So it’s a scary idea. It’s a hard problem. And so I think there’s also, on that reliability side, a lot of hesitancy about what that shift looks like.
Could you speak a little bit about dispatching?
Anything in particular about it?
The ordering of dispatching, because I’ve seen finances of wind farms get messed up by being shut down at times they weren’t expecting.
Yeah, so the economic dispatch processes I described– so all the suppliers will offer their marginal costs of producing energy into the auction, and the auction will take the lowest-cost offers. Is there chalk here? So you have all these offers that look like that. So from lowest cost up to highest cost, you stack them up. And the market will say, I need this much energy to supply my demand, and so this becomes the price.
So as you start adding more and more zero-cost energy, this curve shifts to the right. So maybe the curve looks like that, and then this becomes the price, or maybe the curve shifts like this. Or maybe the demand in the middle of the night is over here, and so then there’s a zero-cost.
And this clean energy resource that’s offering zero, it thinks, I’m free to operate. I’ll be able to operate all the time, but not all the time. So if you have more of this zero-cost resources available than the demand on the system, some of them are going to get shut down.
Thank you. This was a great explanation. I’ve been trying to suss this out for a while. I know this is about ISO New England, but do you have an opinion about some of the other multi-state markets, and have they been able to address this at all, like PJM or MISO?
Everyone is trying to figure this out right now. Everyone has a slightly different approach to it, but everyone is trying to figure this out right now. And nobody has an answer yet.
Right in the middle there.
How does this system or any of its proposed changes deal with time of day? So for example, you could have all the renewable energy you need in the middle of the day, but that still doesn’t do anything for peak, evening period or getting you through the night.
Right. So there are a few ways to address that. One is storage, as somebody else asked about, to shift it around. There’s a small amount of storage on our system, but not enough to sort of shift everything around.
One of the ways you deal with that is fuel diversity. So in a system of looking at clean energy resources, generally, wind and solar are complementary to each other, and then hydro can used to fill in the gaps and firm things up. And the more diversity you have of resources, both in technology type and geographic dispersion, so that when a wind front comes through, or when a cloud mass comes through, it doesn’t hit all of the solar panels at the same time, that helps with the types of issues that you’re describing.
So this is based on not having storage for the energy– so this is based, I’m assuming, on the fact that, right now, we don’t have large storage capability for renewable sources like wind and solar. We do have storage solutions coming down the pike, as the expression goes. And wouldn’t that change the picture and make the pricing approach become different, because now, as a supplier, I couldn’t know what my capability is to provide without having to guess on what the weather is like?
Yeah, so what I was describing here– there are many issues that storage does solve, but what I was describing here is not solved by storage. So at the point where our system is almost entirely made up of resources that have zero costs to actually operate and produce a megawatt hour, if you can store some of that and provide it at another time, there’s no money at any time of day– or basically no money at any time of day– so shifting it around, which is what storage can do, doesn’t solve that problem.
But as a business guy, I look at it from that point of view. I know, with storage, what I can provide, and what I can supply, and guarantee that I can do that. So when I go for financing, I can go, and I can say, I have the capability of supplying reliably x number of megawatts, and I know that it is there, because here’s what we have.
Yeah, so what he was asking was, if I’m storage, and I know what I can produce, I can provide reliable supply. Can I go and get financing with that? And only if you’re getting paid for it. So what are you getting paid for? If you’re getting paid the energy market price of zero, no. If the market changes and provides you a price signal, and provides you profits or revenue for that service that you’re providing, then yes, you can go and get financing and build that storage. But that’s part of the problem, that the markets that we have right now don’t necessarily properly value that and properly pay for that.
I’m getting the great signal there. We actually have time for maybe one more question, and then– so who’s really been waiting a long time? Right up in there. You have been waiting quite a long time. Gentleman in the light-blue shirt.
Thank you so much for the presentation. That was really excellent. So why can’t renewables just bid their levelized cost of electricity? Is there a regulatory requirement– OK.
So that as fairly simple. You want to take another question from someone else, perhaps– or why don’t we design a system where they’re permitted to bid their levelized cost of energy? Obviously, there’s challenges in forecasting that, based on how many megawatt hours you’ll actually be able to provide over the lifetime of the project, but that seems like a solution.
So the main problem here is that the marginal cost isn’t actually the only price signal that we need, or the primary price signal that we need. So the simplest solution seems to me to be to shift it to a market where the price signal is based on the levelized cost of energy, rather than the marginal cost. Thoughts?
Yeah, so you get into difficulties there. So let’s say your levelized cost of energy is just below or just above what the market price is. And maybe you’ve already built your plant, and so you’re trying to recover your costs, and so why not shift your offer just a little bit below the market price, so you can actually produce your megawatt hour and operate, so that at least you’re recovering some of your costs. But then the next guy, they’re going to shift their price a little bit below that, and everyone’s just trying ‘m shift–
–so then you end up back down at– what’s my break-even point where, if I produce this megawatt hour, I’m going to lose money? So that’s what ends up happening with that. But if you look at it on a long-term basis, you look at the requests for proposals that the states run for long-term contracts, that’s what they’re doing, but on a long-term basis.
So this RFP that Massachusetts just ran that selected this import from Canada, there were over 8 gigawatts of resources bid in to provide– they were looking for just over 1 gigawatt of energy. So over 8 gigawatts of resources bid in for a 20-year contract, I think it is. So they’re all trying to give the most competitive price that they can for what they actually need to build their project. So in some ways, maybe that’s our market. But that’s out of the market, and that’s a state contract, separate from these wholesale markets. But that’s what you’re talking about.
I’m afraid we– this has been great. Thank you for coming, and thank you, Abby.