Exclusive interviews with CEOs at five regional independent transmission system operators: Phil Harris, at PJM; Gordon van Welie, at ISO New England; Yakout Monsour, at the California ISO; Graham Edwards, at MISO; and Mark Lynch, at the New York ISO; • Grid Congestion • Price Volatility • ICAP/LICAP • Climate Change • Market Monitoring • Internal Governance • Geographic Expansion
Fortnightly: We read that congestion is growing. Is that true, and if so, is it a bad thing?
Harris: No. Congestion has nothing to do with markets. Congestion has always been there on the electrical system. What we’ve been able to do is provide transparency: information transparency and price transparency about congestion. Once you provide the information and the price transparency, then you are allowing market forces to relieve that, because now you can price it. If you can’t provide the pricing and the information transparency, then you’re leaving everything up to the black box of the utility—for that local utility to optimize their own resources—which may not be in the public interest.
Fortnightly: Is it enough to provide information for market participants to rationalize congestion in a monetary form?
Harris: The battle about markets is really a battle about information. In PJM, and in the other organized markets, we provide all of the information that a control area operator needs. And because it’s available publicly, anyone can see it. They can bid and participate. That’s why, at the recent [American Wind Energy Association] conference, they said it costs them 20 percent more money to try to operate in a non-market area, where you don’t have price information about the dispatch.
Just look at our data. Get on our Web site and let our staff walk you through it. FERC Commissioner [Jon] Wellinghoff was here. We sat down and he was just absolutely flabbergasted by all that system information: How much is flowing, where the flows are going, what’s happening to load, what the prices are, etc. It’s all updated every 5 minutes. It’s huge.
Fortnightly: Would you say that new grid projects—like the AEP Interstate Project and the Trans-Allegheny Project—have come in response to locational marginal price (LMP) differentials?
Harris: Absolutely. And the numbers are real and compelling. You’re looking at probably close to $10 billion dollars in projected construction under review. You’re looking at construction relieving about a billion dollars a year in congestion.
Fortnightly: We still read critiques of locational marginal pricing—that it creates a windfall for generators, because low-cost coal plants can bootstrap their prices up to gas-fired clearing price. Why the outcry?
Harris: When I go to the supermarket to buy an apple, I pay the going price, not the price based on the grower’s actual cost of capital, whether that apple is local or whether it’s imported from South America. That’s how every market works.
Now for those areas of the country that are still stuck in the old paradigm, it’s foreign. They have a lot of difficulty dealing with [LMP] and they don’t want to deal with it. They abhor it. But it doesn’t matter. The point is that technology is changing.
Look at ERCOT. Look at California. New England started on a new path, but they ended up scrapping it. Every area of the country that has started without LMP, but still wants markets, has ended up paying through the nose.
Fortnightly: What about removing price caps—going to an energy-only market, or full nodal pricing for load? Can we overcome the stumbling blocks?
Harris: We can get rid of every bit of that tomorrow, if every state will allow the full floating price every five minutes to be reflected in the customer’s bill.
Fortnightly: What about the software? Do you have the wizards who can make this happen?
Harris: Sure. That’s no impediment. The problem is that the public will not tolerate the volatility of the short-term price spikes. Just look at what happened in Maryland. Look at what happened in the Midwest, in May of 1999. No policymaker will tolerate short-term price volatility at the retail level.
Up and until the time that states will allow retail customers to see the real-time prices, and pay the real-time prices, you’re forced to create square-peg/round-hole solutions; to create surrogates for scarcity pricing. And that’s all that RPM [reliability pricing model] is—a surrogate for scarcity pricing. You can’t be “energy-only” until people can pay the price reflecting scarcity. And we don’t control that.
Fortnightly: So it’s a matter of consumer education?
Harris: No, it’s a matter of public policy. The policymakers in each state must decide what is better for their citizens. Are they better off allowing them to see and pay the real-time price of electricity? If they’re not, because of the volatility and how high the price can get in the short term, then the only thing you have left is to provide some sort of surrogate for scarcity pricing. We’ve done that, through something we call RPM [reliability pricing model].
You don’t have a choice. Generators have to be able to recover their costs. You have to have enough capacity to run the system. So something has to give.
Fortnightly: What if a state bans imports of coal-fired power or imposes a cost penalty for CO2 emissions? Could your software and markets deal with that?
Harris: Well, we can track it. We can provide the certificates that would track where the energy was coming from, based on the hour and how much was used. We have the databases that can do that type of problem.
Fortnightly: Are you preparing for this kind of thing—for control of CO2 emissions?
Harris: No. I have to manage what my staff does. I’m not going to create models for a hypothetical. It’s not a technology question. Can you build environmental constraints into the dispatch? Yes. Is it the right public policy? That hasn’t even been debated yet. It would take FERC to order us to do that.
Fortnightly: I understand you’re not a for-profit company, and you don’t have stockholders telling you what to do. So what is the driving force that governs your direction at the RTO?
Harris: Regarding corporate form, it was the intent of the original PJM companies to make a true for-profit business out of control area operations, and we’ve never lost that intent. Let’s look at the history.
We went from being a power pool to an unincorporated association. Today, we are incorporated in Delaware as a for-profit limited liability company, operating at a zero profit margin. We pay taxes and everything. We’re the only RTO that is set up on that basis, and we did it so that it would be easier for us to evolve to the next level, whatever that might be. So the way we are structured today was never meant to be the end state.
Fortnightly: What about stockholders? You’re not a co-op, are you?
Harris: No. We recognize the fact that we have no owners per se. We’re a limited liability company; the company is the owner, the only way to get our resources back is that we liquidate. And that isn’t a good corporate model. You don’t have the direction; you don’t have the clarity of decision-making. You don’t have all those good governance things that even a municipal like Jacksonville or MEAG or Nashville has. We don’t have our own cash. We don’t have our own equity. Those factors create a problem with governance that needs to be resolved some time in the future.
So, recognizing that we’re only half-way there, we hard-wired three principles into the operating agreement of the limited liability company, as a fiduciary duty for the board of directors:
• Operate a safe and reliable interconnection;
• Create and operate robust, nondiscriminatory power markets; and
• Ensure that no member or group of members has an undue influence over the interconnection.
Of course, as a corollary to that, to carry out those objectives, we have decided that we must ensure a well-trained, professionally qualified work force.
Fortnightly: But while merchant generators might like price volatility, load-serving utilities might not like volatility. That duty to move markets forward starts sounding like an ambiguous instruction, does it not?
Harris: Well, it is. But that’s also why we have stakeholder processes; that’s also why we’re independent. PJM has filed several times—we filed RPM—over the objections of members. We put in economic planning for transmission after two-thirds of the members voted and said “don’t file it.” We filed it anyway. But we were set up to do that very thing. If you truly believe in markets, then somebody somewhere has to have the mandate to create markets.
Fortnightly: When you make a decision like that, such as to institute the RPM tariff, how do you decide to go against the wishes of your members?
Harris: Well, we are regulated by FERC. And there’s exhaustive due diligence. We hold hearings, we hold stakeholder meetings, we allow for oral comments to be provided directly before the board.
But some things you have to leave to the policymakers to make the final decision. No amount of stakeholder process is going to reach a consensus.
For example, look at economic demand-side response. There was no way that the competitive markets, which have a competitive advantage by not having that, were ever going to vote to have it. So somebody had to say it’s in the public interest. Things have to get done. That’s the value of an independent RTO with decisional authority.
Fortnightly: And this somewhat muddy process won’t leave you open to worries that some market participants have undue influence?
Harris: First, before something gets effectuated, it has to be approved by FERC. Second, if members feel that the board is out of hand, they can dismiss the board. Two or three members of the board are up for re-election each year. Third, it also shows why ultimately the corporate form needs to mature to become more normal, the way normal commodity trading works, the way more normal industries work. I think RTOs and ISOs are transitional corporate forms.
Fortnightly: Does that mean that we’ll see an RTO issuing an IPO one of these days, so we can buy stock in PJM?
Harris: I won’t see that in my lifetime. But I do think it’s a fair statement—I don’t think anyone would disagree—that as a corporate form, we don’t have all the alignments between the assets, the owners and the accountability. We have to depend on very complicated, convoluted stakeholder processes for decision-making. That isn’t a long-run sustainable model. Look at PJM. We’re on our third corporate form. But it was never intended to be the end state.
Fortnightly: Do you foresee any consolidation in RTOs? Do you think we’ll have more or less in 10 years?
Harris: I definitely think you’ll have more. Let me give you an example.
With the expansion of PJM, because you have a better economic dispatch, the heat rate goes down. We saved over $500 million last year. And now quantify what that means this year, with the higher gas prices.
Then look at what happened with our demand-side programs. There was $600 million in savings during one peak-demand week and it only cost us $5 million. Now I want our staff to take that $600 million and convert it to pounds of CO2 or barrels of oil for electricity that wasn’t generated. This is a huge public policy good.
Fortnightly: Have you thought about television advertising?
Harris: I don’t have the budget. But we do have a huge energy problem in this nation that needs to be solved. The PJM region, by itself, is about 8 percent of the North American gross domestic product. So what we do has a huge impact. If we could have the entire nation involved in security constrained economic dispatch, with 12 RTOs, the savings would be huge.
But now let me flip the coin to the other side, and tell you what the problem with markets is. First of all, we’re not going to have the “standard market design.” Everyone agrees with that. But what that has forced us to do, what has happened to us at MISO, PJM, New York, New England, California, ERCOT, Alberta, and so on, is that 65 percent of our market development software is custom-designed.
But for my grid operations, almost all that software is off-the-shelf. Only 5 percent of it is custom. If you’re writing custom software, it’s extraordinarily expensive. And then it has to be repeated every three to four years. It doesn’t make economic sense to have all these RTOs all writing custom software to do the same thing. That’s where the cost comes into it.
And another source of cost is clearing. We don’t have the clearinghouse functions like normal commodities do, where they clear every day. As a result of that, we have to have these huge collateral deposits. PJM has nearly $300 million in cash deposits on hand, to collateralize the monthly bill. That’s $300 million that’s taken out of circulation. That’s not good.
Fortnightly: How do we get this done, to create a better system for financial clearing? Who makes the first move?
Harris: Well, I don’t know. Our members largely do not want it, because for those who are paying the bills every month, that’s a nice thing. And yet we know from a market point of view that all commodities work with clearinghouses, because you clear daily. You spread the risk. So we know that for us, the dollars of collateral that we have to hold is increasing to the point of becoming way too much.
Fortnightly: Have you talked with banks on this?
Harris: We’ve talked with everybody. How we break the impasse, I don’t know. But this has nothing to do with the merits or demerits of markets. It has to do with maturing; with getting more normalized market forces in play.
You’ll notice that Fortis bought the Cinergy energy trading platform, but they had to pay a premium for it. [Editor’s note: Fortis announced June 27 that it would acquire Cinergy Marketing & Trading LP and also Cinergy Canada Inc., an Alberta corporation, from Duke Energy, paying a base purchase price of approximately EUR 165 million, plus roughly the same amount again for the value of the acquired trading portfolio.]
We see banks moving more and more into the physical side—getting very close to what happens with the physical delivery of electricity. You can see what’s happening from the Goldmans, the Morgans, the Citicorps. It’s very interesting; it seems like the financial community has recovered from Enron and is getting its sea legs.
Fortnightly: Do you have a potential merger partner there somewhere?
Harris: Well, I think you’ve got two national forces moving. You have RTOs, which are learning how to manage very large grids, for which the nation is better off, as opposed to having a large number of city-states.
And then you have the banks [which] bring the sophistication and the risk-management tools that will provide the hedging and the price certainty.
I don’t know where or how any of these things will link up, but it looks like there’s something in the future that will have to be married.
Fortnightly: How are things going right now with markets in New England? How are you doing with energy prices and capacity incentives?
Van Welie: I think we’ve made some big breakthroughs. The markets have done well, now that we’re entering a maturing phase. Of course, we’ve been through a fairly controversial start-up phase.
We saw a huge investment—more than $6 billion, about 10,000 MW—in new generation in New England from the late 1990s, from when markets opened up until 2003. That was in very efficient gas-fired generation. This helped reduce pollution levels because it displaced older, dirtier units, and decreased the heat rate. This increased the efficiency of New England’s system dispatch because you had more efficient units coming into the system. Overall, our fuel-adjusted wholesale prices decreased over a period of three or four years.
The other thing, which is quite remarkable, actually, is to compare the availability of generation during the early 1990s versus the late ’90s, and into the early part of this decade. We’ve seen a net increase in power station availability. For example, a refueling outage at a nuclear unit in the 1980s and ’90s probably took four months on average—120 days. They now go to great lengths to get it down to less than 30 days. This leads to a higher availability for generation, which translates into less generation needed to achieve the same output, which is a big cost saving. Certainly, it would be very hard to argue that markets didn’t have a benefit.
Fortnightly: How about price volatility and congestion this past summer. Are they up? Down?
Van Welie: Price volatility was up this summer, and there’s a good reason for that. Price volatility is typically correlated to fuel price and high demand levels for electricity. Although fuel prices were at a relatively high level throughout the summer, what drove the price volatility this summer was demand. During the heat wave in early August, New England experienced record-breaking demand, causing us to run the most expensive units on the system. This drove wholesale prices to the cap of a $1,000/MWh.
Fortnightly: Why do you think there is so much opposition to LMP pricing across the country?
Van Welie: If you dig a little deeper, the argument is really whether you’re going to accept marginal pricing in the energy market. Typically, when you dig below the surface, there are other reasons why people don’t want locational marginal pricing—and it doesn’t really have anything to do with whether the markets are good or bad, but it has to do with the local financial interests of those who are resisting the introduction of markets. For example, a vertically integrated monopoly utility with a lot of rate-based generation might be resistant to the idea of competing on a level playing field because it doesn’t want competition for its generation.
Another New England example is when one tries to change something that has been historically socialized—let’s say the cost of congestion. It was formerly spread out like peanut butter, not only across the wholesale price, but across the entire region. Now, however, that price is concentrated onto the area causing the problem, which is typically the area that can do something about it. Well, this type of price signal is unpopular. It’s the same problem in getting demand response to work properly at the retail level. There’s the tendency to want to have uniform, or flat pricing in retail rates, because conventional wisdom makes it unacceptable to have any kind of price volatility at the retail level.
Fortnightly: What about other criticisms of RTO markets—about the bid caps that limit prices, and the band-aids to encourage investment in capacity, such as ICAP, UCAP, or LICAP, when an energy-only market would be simpler?
Van Welie: This is somewhat of a religious argument in the industry. And like most religious arguments, I don’t believe we’ll ever see this fully resolved. From a pragmatic point of view, there is a way to address the issue of ensuring resource adequacy within markets.
To begin, from an economic point of view, energy-only markets are the purest way of doing things. The problem—and here the pragmatist in me comes out—is that experience has shown here in New England that, from a policy perspective, there is no support for the very high prices and the volatility that would have to persist in the energy market in order to make it work. To ensure resource adequacy in an uncapped energy market, it’s been shown that you would need to have prices in the range of $10,000/MWh to $20,000/MWh for 20, 30, or 40 hours a year, in order to recover the capital costs of a peaker, or a quick-start unit. One or two hours is not going to do it. When you look at the overall issue of how to generate enough revenue in a very short number of hours, very high prices in the market needs to exist and reliability has to be close to being threatened. That is just not a comfortable position for people to be in.
In New England, when we originally started with an uncapped energy market, prices roared up to $6,000/MWh in May of 2000. There was a huge outcry, and the result was the $1,000/MWh bid cap that now persists. That, of course, created a problem in the sense that a generator could no longer get full cost recovery in the energy market, and this in turn created the need for a capacity market.
There are really only three ways to solve this problem.
The first approach is to uncap energy markets. The second is an “obligation to serve.” With that, there would be an obligation, created at the state level, for the load-serving entity (LSE) to contract for the needed capacity for the long-term. Most restructured utilities vigorously resist that approach, however, because it creates a liability on their balance sheet in the form of a contract without a corresponding asset. And Wall Street ends up discounting their share price. It’s what utility companies are fearful of: that their share price will take a hit. Now the way to solve this is for the state authorities to guarantee that the utilities will be held harmless. But that is something that’s not normally forthcoming, so it hasn’t found much traction.
That leaves the third approach, which is some form of capacity market. And really there are only two basic types. One is a spot market—UCAP/ICAP, or LICAP, which is the locational version of it—but the problem is that it looks administrative because there’s no way to come up with a real value of lost load, so the creation of a sloping demand curve administratively provides a price for capacity at different quantity levels.
Fortnightly: Wall Street didn’t understand LICAP. In fact, a lot of people didn’t understand it.
Van Welie: The parameters of the LICAP demand curve are complicated, but relatively simple to administer, once the demand curve parameters have been set. This was a proposal that had been developed in New England, but we failed to get a supermajority of stakeholders to support it. So a compromise was reached on a second type of capacity market, the forward capacity market. From an ISO perspective, it will be a complicated system to administer. It’s a forward auction that procures the estimated amount of capacity three years into the future. And the price for the capacity is set in the auction, so you can’t argue that it’s not a market-based price.
The auction clearing price for new capacity is the price that is then paid to everyone supplying capacity. It’s a longer-term auction; it looks a little like an RFP, if you think about it, because there’s a five-year commitment period to new capacity resources.
And the other thing it has built into it is a very high penalty for non-availability of generation. Which, ironically, is what the energy-only market would produce. An energy-only market is designed to create a very strong incentive to be available, because a resource only gets paid in an energy-only market if it’s actually running. Therefore, the idea in a forward capacity market is to try to mimic that as much as possible.
Fortnightly: Suppose some states in your region imposed a partial ban on imports of coal-fired power, or some sort of cost penalty or tax. How would that fit within your market structure? Are you preparing for this now?
Van Welie: It doesn’t impact the markets, per se. The markets will price any regulatory constraint, and that’s what you are doing: A regulatory constraint is being added that will affect the price of electricity. You already see that coming with RGGI, the “regional greenhouse gas initiative” (see, www.rggi.org), which will cap the amount of carbon that generators can emit. We’ve done some studies that show what the implications will be over time. The bottom line is that existing coal-fired generation will have to be displaced with something that doesn’t emit as much carbon, or owners of those facilities will have to invest more in technology to clean up their emissions—all of which will be reflected in the price of electricity bid from that unit. So the net effect over time will be increased wholesale electricity costs. However, because of the reliability constraints, I don’t think anyone will be so rash, as to stop importing coal-fired electricity from one day to the next.
Fortnightly: So your forward capacity market incentive is neutral on the question of fuels and emissions?
Van Welie: Yes, it’s designed as neutral. Obviously, resources that bid in to the capacity market will have to price in any and all constraints mandated at the state level. We’re procuring resources at the wholesale level, but the pricing is affected by where you intend to build, and what the state regulations are. It is conceivable to have a situation where someone wants to build something in one part of the system, but ends up not being competitive with resources available in another part of the system.
For example, if one state imposed very draconian environmental regulations, it would actually end up making the local resources less likely to clear in the auction. And so the interesting thing—and this is something that RGGI has thought a lot about, and why they’re trying to get all of the Northeastern states to sign up—is that you get the issue of “leakage.” How do you stop the electrons from coming in? A neighboring resource might be noncompliant, but the electrons come in anyway through the transmission lines. They just follow Kirchoff’s laws. What you’ve essentially done is you’ve moved the siting and/or environmental problem into somebody else’s backyard.
That issue is something that the states will have to work through in the RGGI process.
Fortnightly: ISO governance mystifies many people. Haven’t there been situations where the ISO membership votes against filing a new tariff, but the ISO management goes ahead anyway?
Van Welie: First, you should be aware that ISO New England has never gone against a majority vote, but we’ve gone forward sometimes without super-majority support. LICAP was a good example, where we went forward with a 59 percent level of support, where the governance called for a super-majority level of support, which was two-thirds.
Of course, the ISO is still accountable to FERC, its regulator, and to its stakeholders, through its stakeholder process. We have a very well defined governance process that commits us to take any substantial proposal to our stakeholder body for a vote and then deliver the results of that process to the FERC. So we’re transparent in everything we do. There is no decision-making behind closed doors. Everything is debated very thoroughly. The matter then goes to the FERC for review, and even if the FERC rules in our favor, opponents still have the option of going through the court system. The accountability comes through the stakeholder process, through the regulatory process at FERC, and, ultimately, recourse is available through the court system.
Fortnightly: Are you happy with the way the checks and balances play out? Do you have a good mix of stakeholders to represent all sides?
Van Welie: Yes, but I don’t think any system is ever perfect. There have been calls by some parties to change the governance of the ISO. The LICAP debate brought out those calls. But typically those calls were made by folks who wish to control the independent decision-making process of the ISO. And that goes back to one of the basic principles. An entity is either independent and will act in a transparent way and make decisions in accordance with its mission—and that would be to ensure reliability and efficient markets—or a different type of entity would be created, which would be controlled by those that have a vested interest in the outcome.
Fortnightly: Do you think we’ll have some regions where we’ll never get an ISO or RTO? And how about the number of RTOs going forward—do you anticipate consolidation or multiplication?
Van Welie: On the first question, it depends on your time frame. If you project out 30 or 40 years from now, there will be some form of competitive market everywhere in the United States. But I don’t see it happening in the near term, and the status quo will prevail in the next five, 10 or 15 years. We’ve evolved about as far as we’ve been able to at this point. It would take a combination of national and state consensus to move forward, and we don’t have that at this point in time. I believe the evolution of wholesale markets across the entire footprint of the United States is about as good as you’re going to get right now.
On the footprint issue, the size of ISO/RTO is much more governed by regional interests at this point then the economies of scale of operating an ISO.
Fortnightly: And when you say “regional interests,” do you mean state regulators and legislators and so forth?
Van Welie: Yes. The regional stakeholders have a lot of influence over whether an ISO/RTO footprint can expand or not. We saw that very clearly when we explored the possibility of a three-way merger among PJM, New York, and New England, and later on the two-way merger between New York and New England.
Also, when you look at the price of an ISO in absolute dollar terms, it looks like it’s a lot, but when you look at it in the context of the market it is administering, it’s actually a very, very small number. Take the cost of the New England ISO: It’s essentially 50 cents for the average consumer per month. There is some economy of scale that could be realized if you were to combine the New England and New York operations, but it would only be realized if you are prepared to standardize the market. Regional stakeholders would have to be comfortable with the fact that they would have to give up their particular flavor of market design. And that, I think, has proven to be a very difficult thing to do. There’s just no desire or cost-benefit that regional stakeholders see in going down that path.
If New England were to merge with New York, for example, the debate would be about which one of the two capacity markets you would want to implement. The simple answer is, I don’t see anything changing in RTO footprints anytime soon.
Fortnightly: How about an IPO? Will we ever see the day that I can go to my stockbroker and say, I want to buy 100 shares of ISO New England?
Van Welie: I don’t see it. It’s the same reason that caused stakeholders very strongly to want the ISO to be not for profit. I do see that what I call the “forward markets” will continue to evolve. Entities such as NYMEX will continue to develop products that are traded forward of the ISO markets. And in that world, you’ll get all kinds of different variations. We’ve seen that happen in Europe as well. But when it comes to the ISO, RTOs—the real-time operation of the grid and the pricing of electricity in the so-called spot market—I don’t see a great deal of change.
I have one other comment on this last point. If you look around the world, you’ll see different variations of the day-ahead and real-time spot market approach that we have in the United States, with an ISO or RTO running the markets.
For example, there’s the Transco model in the UK, where the grid operator is also the spot-market operator, and everything forward of real time is actually done by the exchange, which is a for-profit entity, outside of the RTO. Those models work as well, so the issue becomes, how much gain do you get changing from one model to the other?
Well, I don’t think it’s clear that you get any gain. But what is more important in the United States is stability.
Fortnightly: How is your ICAP (installed capacity) plan working in New York, since it doesn’t appear to have the same locational character as the LICAP (locational installed capacity) plan that was proposed in New England, or the RPM plan in PJM?
Lynch: First of all, the NY-ISO’s ICAP market is locational. We essentially have three specific zones: With Long Island, New York City, and then the rest of the state. We’ve actually had a locational market since we began.
Fortnightly: So you are as locational as you need to be?
Lynch: We believe that to be true. You bring up a good question when you ask about location and investment. The capacity market itself isn’t the only mechanism that sends locational signals. We use locational marginal pricing in the energy markets, in the day-ahead and real-time markets, and we actually think in New York that on the energy side, in conjunction with the capacity side, some very strong signals on investment have been sent.
Looking at the investment that has actually come into the market since our formation in 1999, we’ve had more than 5,000 MW of new investment, predominantly from the Capital Region, New York City, and Long Island—essentially right where the pricing has indicated that they need to be.
Fortnightly: In the wake of what happened in New England, with the demise of LICAP and approval instead of what they call the forward capacity market, without any demand curve, has there been any discussion in New York about moving away from a demand curve and going with an auction instead?
Lynch: I don’t know if we have specifically talked about that. But even prior to the New England settlement, we had had discussions with our market participants about whether we should look at a more forward type of capacity market.
You suggested that we might abandon the demand curve. I am not too sure you need to abandon the demand curve. I think you can go to some type of forward capacity market, but still employ that demand curve. It helps to level some of the boom/bust aspects of the market.
Fortnightly: So you would be looking at some sort of forward obligation, rather than just a monthly auction?
Lynch: Right. What you’d probably be looking at, to be somewhat hypothetical here, could be some type of a forward auction. We could look at some type of program where bids and offers are put in place and we match those up on a longer-term basis.
Fortnightly: Do you see any chance of moving to an energy-only market, removing the caps and relying on that price, without a supplemental capacity market?
Lynch: I would have to say that for the foreseeable future I think bid caps are a political reality here in New York and potentially the Northeast.
Fortnightly: Has the ISO been involved in any discussions concerning climate change, imports of coal-fired power, or controlling CO2 emissions?
Lynch: We have been involved in a lot of discussions, specifically RGGI [the Regional Greenhouse Gas Initiative, see www.rggi.org]. What we consider ourselves to be is more of a resource—a source of information on the impact that these environmental initiatives may have, on the market or the reliability of the system.
Fortnightly: If there was a restriction on operation of coal-fired resources or imports of coal-fired power, would that show up in your dispatch algorithm as just one more constraint?
Lynch: Constraint is an interesting word. What I think would happen, in-state, is you would see an increase in the cost of production of electricity, because the facilities that would be emitting the CO2 in the case of RGGI would have to add the cost of allowances. Either they would be given sufficient allowances or they would have to go out and purchase allowances.
On the issue of transactions in and amongst different control areas, between New York and PJM, or with ISO New England or our neighbors in Canada, it presents an interesting hypothetical. Some of that trade is interstate commerce. I don’t know how you look at that or control that. My hope is that we will have an opportunity to voice some analysis on it—again, strictly from a market and reliability impact.
Fortnightly: How do you conduct market monitoring in New York? Is your present scheme working out?
Lynch: Actually I think we have one of the most robust market-monitoring units of any of the ISOs or RTOs.
Fortnightly: But it’s internal?
Lynch: Yes, it is internal. We do have an independent market advisor who reports to the board, but who also collaborates with our internal market-monitoring unit. Our market-monitoring unit is a very large department. You have to remember: New York has a lot of programs in place to make sure that there are no abuses of market power. We initially had our AMP, our automatic mitigation procedure. We have now brought that back to the extent that we now have an AMP plan within New York City. For the rest-of-the-state zone, however, we conduct an actual physical analysis, looking at conduct and price impacts, because we did not think it was necessarily appropriate in that zone to allow for automatic price mitigation.
As I mentioned, we have an entire internal department that analyzes bids and behavior on a daily basis. They have conference calls with FERC, where they look at market behavior and monitoring. Again, you’re being the police here or the watchdog to identify issues and allow FERC to take specific action.
Fortnightly: Do you see any consolidation between regional RTOs in the future, or perhaps some additional RTOs around the country?
Lynch: I would have to say that I think in the near term that you probably will not see the new formation of markets. And from a geographical standpoint I don’t really think it is necessary to combine markets. I think as long as there are compatible market roles across the various organizations, there really is no need for a merger. But looking out 10 years, I think more people are going to see the value of competition.
Look at New York. We have seen a dramatic improvement in availability and efficiency of our operating fleet. And think of the value of shifting the risk of investment from your consumers over to the investors.
When the market sends locational price signals, it drives investors to build the infrastructure and to have the facilities located where the need is, as opposed to building them in remote areas. In 10 years, I think it is very conceivable that you could see new areas of markets pop up. It is going to take some time, though.
Fortnightly: Any other ideas come to mind on the current state of markets, plant efficiency and availability, or congestion?
Lynch: I want to make several generic comments on congestion, because it’s getting a lot of press right now.
First, in a market, congestion is not necessarily bad. It allows us to send the right price signals and send the right locational signals.
Second, when you look back on the history—power pools and integrated utilities—you find that there has always been congestion in our system.
Third, if you were to do studies of congestion today as compared to maybe three or four years ago, a lot of people would say that congestion costs are a lot higher. I think you need to realize in an organized market that what you’re seeing is the effect of higher prices for the underlying fuel, as opposed to a higher cost of energy because of congestion.
Fortnightly: You’re saying congestion is evidence of trade, simply the coin of the realm?
Lynch: That is one possible aspect. I don’t want to say that there are never reasons why you would want to alleviate congestion from a reliability standpoint. You need to analyze why, how, and what signals you are sending with the congestion—what is the result of that—before you arbitrarily assume that you have to alleviate all your congestion in the market.
Fortnightly: Going forward, what is your message to investors, and to Wall Street and the business community?
Lynch: Within New York, and I think it is true for the whole Northeast, we are going to be entering into less of a revolutionary phase and more of an evolutionary phase.
We just came out with a new standard market design last February. We have our demand curve in place [the ICAP capacity market]. We want to make incremental improvements and enhancements that are evolutionary and provide benefit to the overall market, but we don’t want to look at revolutionary changes that won’t provide regulatory certainty.
We want to make sure that the investment community realizes that we are looking at evolution at this point, not revolution.
Fortnightly: It’s no secret that MISO is going its own way on the UCAP/ICAP/LICAP issue—that you’ve put out some white papers on the concept of an energy-only market. Why did MISO members decide to go a different route?
Edwards: As far as resource adequacy goes, I’m not sure there is a right or wrong way to approach it, or a right or wrong answer, from the perspective of what’s going to drive steel being put in the ground.
Theoretically the energy-only market provides a viable solution. But in reality, whether it will be allowed to work and be allowed to happen is a completely different question.
Will price signals be adequate to incentivize baseload generation and the required operating and spinning reserves? I am concerned that politicians or regulators will not allow prices to get to the point where they need to be to stimulate a baseload coal-fired or nuclear unit. Peaking units, yes. More demand-side response, yes. But the more hours in the year that you see prices at $1,000, $2,000, or $3,000 a megawatt-hour, I think the regulators are going to say that’s unacceptable; they are not going to allow that to happen.
I believe it is a responsibility of the states to determine what level of resource adequacy is appropriate. We will work with our Organization of Midwest ISO States (OMS), the regulators, and try to determine that level, not just on a state-by-state basis, but over our footprint as well. We are working with the regulators along those lines.
We think that for the short term, the energy-only market approach is the right approach. We also think theoretically for the longer term it’s correct. However, reality says that probably the states need to get involved.
Fortnightly: You may find your states coming back and saying, “We want a forward auction like New England.” That would send you back to the drawing board?
Edwards: I think that whatever is best for our footprint, we can accommodate. If regulators want some kind of forward capacity market and we buy into that, it’s just a matter of what’s the best way to develop that. We want to do what’s best for our footprint. To us right now, that means energy-only, with the states having the authority to determine the appropriate level of long-term adequacy.
Fortnightly: Have you documented for OMS how high the energy price would have to rise in order to make an energy-only market work?
Edwards: I am not sure that we have said it has to be a minimum of $3,000/MWh, for 100 hours a year. We have not gotten that specific.
[Some additional comments follow from John R. Bear, senior vice president and COO for MISO]
John R. Bear: Specific prices are difficult to discuss because they are going to be dependent on fuel prices, which are pretty volatile right now. The key thing that Graham has noted is that the states have the authority to establish the appropriate level of long-term planning reserves. What we want them to do is establish that; then we’ll create the market from an energy-only standpoint—whether day-ahead, real-time, or forward, as Graham referred to—to allow that capacity to change hands efficiently. The critical first step is for the states to set that level.
Edwards: The main thing is to have sufficient steel in the ground. The commissions, of course, are going to drive that. We just need to make sure that we don’t get out in front of them.
Fortnightly: How is congestion going? Any big surprises, now that your markets have been up for a while?
Edwards: Number one, we think that the security-constrained economic dispatch, the five-minute dispatch that we use to solve congestion problems, works better than the old TLR process (Transmission Loading Relief). And let me tell you why I say that.
The Independent Market Monitor, Dr. David Patton, reviewed the historical market and the first nine months of the operation of the new market. He gave us a pretty high grade. He said the markets were working; that there was price transparency in the market, which is one of the main things we were trying to accomplish.
In that evaluation process he compared the first nine months of market operation to the same nine-month period of 2004, when we were using TLRs versus unit dispatch to solve congestion. He saw that about 85 percent less energy was displaced though the unit dispatch commitment process versus the previous TLR process. In other words, we had to interrupt fewer flows on the line to solve congestion problems. That 85 percent would equate to about 800,000 MWh that we were able to handle thought the unit dispatch without using TLRs. If you assume that a lot of what was interrupted through TLRs would have been done during peak periods, when prices are higher — let’s say $100 a megawatt-hour, which is probably low — then you’re talking of a savings of about $80 million on that particular item, since the market started.
Fortnightly: Some ISOs on occasion have proposed a tariff to FERC without obtaining a majority vote from members, or without the super-majority vote required in some cases. How are you handling that?
Edwards: First of all we have a seven-member independent board of directors. Those seven members are totally independent of the organization other than the fact that they serve on the board. They cannot have had a relationship with a market participant for two years prior to coming on the board. There’s a cooling off period, which is normal.
We do not have a hybrid board, where we have stakeholders on the board itself. Our board is completely independent. Having said that, I think everybody realizes that you have got to build consensus to be successful in this business. And that’s what we try to do with market participants: build consensus to resolve issues. Not to please everybody, but to build consensus on where you need to go from a business perspective.
Have there been occasions where the board has taken positions that are not in alignment with the advice or the majority of the advice that came from the Advisory Committee? Yes, there have been. But that’s the exception and not the rule. The normal rule is that we build consensus.
However, when it comes down to it, from my perspective the board has got be independent to make those tough calls—when you’ve got half of your constituency saying one thing, and half of it saying something else. To me a hybrid board makes it very difficult for that to happen.
Fortnightly: What about the footprint going forward for MISO? I understand there’s a plan for some kind of market consolidation with PJM. Is that on the back burner now?
Edwards: We have initiatives going forward. We are evaluating many aspects of a “Joint and Common Market” with PJM. However, we think that we can solve a lot of seams issues—issues associated with differences between our processes and their processes, and our tariff terms and their tariff terms—and then reconcile all this by agreement between us without having to say “one market.”
What we are trying to do is work with PJM, and they with us, to determine the commonalities between us. How can we improve our seams agreements? How can we improve our joint operating agreements to extract as much value for the market participants as possible?
At some point, does it make sense to have one market? In an ideal world that might be the case, but we have evolved where we are today and we think we need to take it one step at a time.
Fortnightly: How about in the other geographic direction? Do you foresee any expansion of MISO to the West?
Edwards: Well, I think that through the reserve sharing plan that we are going to implement in the latter part of this year with the Mid-Continent Area Power Pool region, with Mid-America Interconnected Network, and the East Central Area Reliability Coordination Agreement all combined into one for reserve sharing, that we will continue to build the coalition. We just have to take it one step at a time. A lot of the entities to the west of us are public power entities. We need to make sure that we can articulate and demonstrate the benefit and value of being a part of the Midwest ISO.
Can we grow the footprint? We would like to. I think the footprint is going to grow a little bit just through growth of our current market participants. But I would like to see some additional participants come in and become part of Midwest ISO to add value to their constituencies.
Fortnightly: How are you progressing on the California ISO’s new proposed market design, the MRTU (Market Redesign and Technology Update)? Can you give us an overview?
Mansour: The market design of California has been progressing since 2001. From the beginning, until we filed our final application this past spring, I think we have had something on the order of 20 separate FERC rulings on various aspects on the conceptual design.
This last filing was not a kind of big bang, if you like. It was a progression, one in a series of pieces—some of it detailed, some of it conceptual. We are hoping there will be no big surprise, regarding FERC’s answer to our latest filing. Our issues are not very different from what FERC has seen in other places. The development of the systems is on track, hopefully, for full implementation in November 2007.
Fortnightly: How did you conquer any prior opinions about things like FTRs (financial transmission rights) and locational marginal pricing with a full nodal model? Did you invite some people from PJM, New York, or New England to come out to California to win over your audience?
Mansour: Absolutely. We conducted workshops and yes, we did invite some people in who had experience. The California entities were a bit skeptical about some of those Eastern models, like LMP and what have you. And as you know, we went to a zonal kind of approach at first, but the zonal approach got to the point where we had to live with problems. Most of the congestion is inside the zones, so we had no effective, efficient mechanism to deal with it. It got to the point where the intra-zonal congestion got so high—and it was spread among all in the system—so it could not send the right signal.
Certainly the IOUs (investor-owned utilities), who have 75 to 80 percent of the load-serving responsibilities, are supportive of moving ahead. Some others, whether they are skeptical based on fear or based on knowledge, we just have to work with them.
Fortnightly: Was this change made more difficult by the California market problems and political problems of about five or six years ago? Or was it easier, because your people realized they had a problem?
Mansour: I believe the former. A lot of California is still living in the shadows of 2000/2001.
Fortnightly: So it was more difficult?
Fortnightly: I understand that the staff of the California Public Utilities Commission (PUC) suggested a while back that the state might adopt a locational ICAP market. Has the ISO taken a position?
Mansour: We’re exploring, and working with stakeholders. We monitor the PUC closely, we monitor FERC closely, and we work with all our stakeholders to find out what will be the best choice for California. At the end, however, we will do what those entities, combined, want us to do.
And you know, at the ISO we understand ICAP and LICAP and so on; we understand energy-only markets. We know the pros and cons of each. But none of them is perfect. When you go to any capacity-based market, the most difficult part of it is defining the product. That’s number one. And number two is pricing the product. Then comes the allocation of the costs. The difficulty is reaching agreement on each of those three, as we’ve seen lately in New England, where they struggled with each one of those issues.
When you go to an energy-only market, however, you don’t have to struggle with defining the product. There’s no struggle for pricing it, as long as you accept the idea of letting the price go as high as it needs to be.
Fortnightly: Do you have a sense of just what that figure is? Would that be $5,000/MWh? $10,000/MWh?
Mansour: It would be in the thousands. It would be certainly several thousand.
Fortnightly: Do you meet regularly with the PUC or the California Energy Commission?
Mansour: We do. We are very proud of our relationship with the PUC, and the CEC for that matter. Not that we always agree on everything, but understand each other, we communicate regularly.
Fortnightly: And there is no uncertainty in terms of jurisdiction or how that relationship should be managed?
Mansour: You know, with the jurisdictional issue, we all understand that we could spend the next five or 10 years trying to sort it out. Or, we could sit down and say, “How can we actually make it work?”
Fortnightly: Would market monitoring run into trouble, given the current structure of the ISO?
Mansour: I’ve said it before and I maintain it: I would love to see an independent market monitor for the entire West. But we would have to have the same rules for everyone; with penalties and with everyone held accountable in the same way. Now when you have an organized market like California, it is easy to pin down. But that is difficult to achieve when you have other markets that are still vertically integrated, without transparency.
Fortnightly: Currently, at the ISO, do you hire a consulting firm for this?
Mansour: No, we have a market-monitoring (MM) unit inside the ISO that technically speaking, reports to the CEO but actually reports more directly to the board of governors. The unit is treated similarly to an internal auditor. Reports from the unit are not subject to the scrutiny of management, including the CEO. The MM unit monitors both the ISO’s activities and market activities, and provides reports to the board of directors. And if management has an opinion on the market-monitoring report, then management actually prepares a report to respond to it.
Also, we have a market surveillance committee, which is a committee of three professionals—actually, I would call them world-renowned experts. They oversee the market activities of the ISO, and they also provide comments on market monitoring findings. This committee reports directly to the board as well.
Fortnightly: Do you have any predictions about whether we will see new regional grid groups forming in the West anytime soon?
Mansour: In terms of a meaningful structure, along the lines of the model of the existing ISOs and RTOs, I think that what you see is what you get for the next 10 years or so. You may see some sort of ad hoc collaborative activities, with limited scope, depending on the need, but not in terms of a full-blown structure like what you see with the ISOs and RTOs of today.
Fortnightly: Are there any new chapters to the ISO story that we should mention here?
Mansour: You asked whether we might see more ISOs, especially as it relates to what happened in California in 2000/01. Well, you might be interested now to hear what California has achieved since then, in terms of creating value under the current ISO structure.
Fortnightly: Do you mean declining heat rates, or better plant availability factors?
Mansour: All of that. From year 2000 until today, California has added 14,000 MW of generation, within the state. So the notion that restructured markets do not invite investment is definitely wrong. Now there have been some plant retirements, which took away about 30 to 40 percent of the added amount, but the fact remains that we did attract much new investment since 2000/01.
On the transmission side, from 1998 until today, the ISO has approved some $6 billion of new investment. And by the end of this year that number will be closer to $8 billion. Of course we still need more, because California is the fastest growing economy, but this is a substantial amount.
Fortnightly: So California is no longer a no-build zone?
Mansour: Exactly. And consider prices. The market-monitoring unit conducted a study in which it took today’s wholesale power prices—both for the ISO market and for bilateral trading, short-term, long-term, everything —and normalized them for rising fuel costs and compared them to 1998. They found that today’s fuel-normalized prices are lower than in 1998. Again, the notion that restructuring doesn’t attract investment and causes prices to rise to high? That’s all a myth. People today have no grounds to say that at all.
This past summer, we met a level of peak demand—had a heat wave close to 51,000 MW of peak—that was forecast to be reached not for five or six years ahead. We met that without a glitch; without repeating blackouts of any kind.
Also the congestion constraint in 2005 was about 40 percent less than in 2004, in terms of cost. We are actually witnessing a level of innovation in both the supply and the services that we have never seen before; innovation in operation, innovation in technology, and innovation in markets.
Frankly, when you look at all of those things and hear people say, “I don’t want to be like California,” I say, well, you mean you don’t want to be efficient, you don’t want investment, you don’t want prices to be low. These are facts.