Kathleen Davis, Associate Editor
In these days of round-trip trading and customer uncertainty, reliability and price stability are more important than ever. One possible solution being bandied about the industry is the concept of demand response.
To get a more in-depth view on demand response and the FERC rulemaking on standard market design, EL&P spoke to three experts in the field: Ross Malme of RETX, Mike McGrath of EEI and Leonard Haynes of Southern Company.
EL&P: What will the upcoming FERC rulemaking outline for the future of demand response?
Malme: FERC has really changed their view on demand response 180 degrees from where they were two years ago. 18 months ago FERC believed that demand response was exclusively the domain of the retail markets, and, therefore, under the jurisdiction of the state public utility commissions. And, in the last year, they have completely reversed that position and now believe that they cannot create efficient wholesale markets without having robust demand side participation.
I believe that this rulemaking proceeding is going to be the benchmark to allow demand response to participate in the wholesale markets on a level playing field with supply. This is a fantastic first step, and I think you’ll see that the Administration, Congress, and FERC are aligned pretty well on this issue.
Mike McGrath, EEI Click here to enlarge image
McGrath: I feel very certain that it’s going to be extremely aggressive. FERC is going to insist that demand response is fundamental to accurate wholesale price discovery. And it’s also fundamental to just and reasonable wholesale rates. In short, they’re going to be taking the position that demand response is a fundamental part of a healthy market.
And we’re in 100 percent agreement with that. We believe that demand response is a fundamental part of a good, functioning market. You’ve simply got to have some way for price takers to respond to price offerers, and this is one way to do it.
Where FERC might go with its rule-making: We think they will require establishment of a demand response market at the RTO level. And, we’re not exactly sure what form that market might be. One option might be a demand bidding market, and that’s where a customer could say, “Gosh, if the price is X, I’ll buy 500 MW, but if the price is Y, I’ll buy 600 MW.” That’s actually the system we would prefer.
But, another way to do it would be to use a “nega-watt” kind of system. A customer says, “Well, at a certain level, I’ll sell you back MW. I’ll just not use ones that I said I was going to use. I’ll simply sell them back to you at a price.” We’re not as fond of that system. Those can be pretty complex, and they require you to estimate what the load would have been.
Haynes: I’m assuming FERC will make retail demand response a part of the market design, and our hope is that they recognize that there are regions of the country, like ours, that already have significant demand response programs in place. We don’t want whatever FERC reveals to conflict with or reduce the effectiveness of that, because we think we’ve got a pretty good program.
EL&P:Will the rulemaking, in your opinion, cover all the bases?
Ross Malme, RETX Click here to enlarge image
Malme: Not necessarily. There are three levels of concern that I’ve got. One: Heretofore, demand response-at least at a wholesale market level-has been limited to larger customers, people who can give us a 100 kW of demand response and above. Now, if we’re going to identify an RTO or an ISO as the “liquidity point” for demand response programs, the public policy folks are going to want all customer classes to be able to participate. So, I think, we’ve got to make sure that the rules allow an opportunity for each customer class to play in this thing.
Two: There needs to be multiple opportunities for buyers. There’s a tremendous value proposition for the wholesale trader-like the Mirant trading desk, for example-for demand response. But, they really can’t play in it today because we’ve built all these rules around ISO-centric structures, so the ISO is the only buyer in this market.
Three: The technology needs to allow for multiple buyers, multiple sellers. And they need to be able to exchange data easily-not just price data, but consumption data as well. So, I want to be sure that there’s some statement from a technology standpoint that we don’t just go build new legacy infrastructure that impedes the market from progressing to the next level.
McGrath: There might be some problem areas. We’d hate to see demand response in a standard market design that facilities customers buying energy at low regulated and non-market prices and then selling back at the top of the wholesale market. This could create the only business in the world where it makes a lot of sense to buy at retail and sell at wholesale. We’re certainly not a big fan of that, and we hope the design doesn’t encourage that.
There also might be questions of cost effectiveness. These programs at the RTO level are going to require investment in infrastructure, or, if the RTO is offering the program itself, investment in those programs. But, what if wholesale prices are low, and it really isn’t cost effective to do the demand response? What happens then? How do we justify that? In fact, that is likely to be an issue in places like the Southeast, where the capacity situation is pretty good right now and there’s less likelihood of high volatility.
There’s also likely to be questions of cost recovery or jurisdictional issues. There’s a concern that if the RTO requires an investment in the demand response system or programs, and then the state later decides that the program wasn’t cost effective or wasn’t prudent, then how do you get cost recovery? There’s a jurisdictional issue there, and we’re certainly hopeful that the standard market design would have some mechanism for avoiding that problem.
EL&P: How do you see demand response developing past the FERC order?
Malme: We believe that getting to the 5 or 10 percent of the maximum demand in a market supplied by demand response is achievable, but we’ve got to look toward investment to get us there.
McGrath: I think demand response will develop to the point where there’s an economic balance, where the cost of operating that program at the system level and the cost to the customer is equal to the price of energy at a particular time.
Leonard Haynes, Southern Company Click here to enlarge image
Haynes: We’re just hoping to continue to build on our already successful programs. One of the things we’ve discovered is that you can’t put a program out there and expect it not to need changes and mid-course corrections. So what we’d hope to see happen in our region is a further development of the status quo, a natural growth.
EL&P: What’s the biggest obstacle to an electric market which relies more heavily on demand response?
Malme: Demand response programs in this country-at least for the last several years-haven’t been programs, per se. Instead, they’ve been projects of 90 days and 120 days. So, what we need, first of all, is long-term markets. We have to have a long-term view on this.
Secondly, we have to have very good alignment between FERC, which can create markets, and the state public utility commissions. What FERC can create, the state can taketh away.
McGrath: There are a few. One of the biggest is the Provider of Last Resort that almost all utilities have. If a customer has the option of a fairly low regulated price without all this worry of real-time pricing or time-of-use pricing or price volatility, why on earth would they agree to reduce demands, particularly when it’s an inconvenience to do so? So I think finding a way to square it with POLR is a must-do.
Another obstacle is rate caps in general. Again, if there are caps in place that prevent the customers from seeing higher prices in particular times, why would they bother?
Haynes: I think we need to recognize that customers only want so much demand response. So, the biggest obstacle to demand response growth is not recognizing the fact that you must tailor these programs around the customer. Customers are willing to respond to prices; they are willing to be involved in volunteer reduction programs. But, there’s a limit to the number of times you can call customers to do that. They have production schedules to meet and customers that they have to respond to, and they are primarily in the business of producing a product, not the business of electricity and demand control. The biggest obstacle may be finding programs that offer customers enough incentive to continue to do more without making those programs uneconomic.
EL&P: If there was one essential statement you wanted to get across to the industry about demand side management, what would it be?
Malme: Over the last several months, we’ve seen some of the dirty laundry about things that have gone on in the wholesale market: round-trip trading and so forth. There’s been a rush to judgment about market transparency, pushed by this airing. Market transparency, however, is not necessarily the way to curb market manipulation. What we really need is four things: price transparency, a standard market design that eliminates some of the seams and allows us to create products, market liquidity and a robust demand response market.
If we can get those four elements into place, you’ll have something better than market transparency, for you will have created an environment where the market polices itself, and I think that’s what FERC is driving toward with this rulemaking.
Demand response is not a band-aid to immediate market problems, but it is an integral part of the wholesale markets going forward to allow those markets to operate efficiently. And it’s a very inexpensive form of risk management insurance.
McGrath: For heaven’s sakes, folks, pay attention to that FERC standard market design. They will be aggressive, make book on it. And, in it, there will be the seeds for great opportunity, but also chaos. The key issues are going to be: Who pays, who plays, and whether the RTO is a market facilitator or a market participant.
Haynes: Demand side reductions are a valuable resource for improving reliability and reducing the need for new generation. However, we can never forget that these types of activities require customers to take action. So, whatever we do has to be done with the concept in mind that this is a product that we’re offering, and it, therefore, must meet the criteria of a good product:
It must provide customer value and be relatively easy to implement.
Malme’s company, RETX, is currently delivering demand response in New York, New England and PJM. They’re installing items at the NYISO and recently worked with Allegheny Power.
Malme is the founder and CEO of RETX, as well as being the chair of the Peak Load Management Association.
Mike McGrath is executive director of EEI’s retail energy services group. He works with EEI staff and member companies on issues that pertain to the nation’s retail energy markets, including demand response.
Leonard Haynes is executive vice president with Southern Company, which has an extensive (and highly praised) set of demand response programs. (See below.)
More information on demand side management and EEI’s look at programs currently in place this summer can be found online at www.elp.com.
Editor’s Note: Due to magazine closing dates, these interviews were conducted prior to the July 31st release of FERC’s Standard Market Design Notice of Proposed Rulemaking (NOPR). Therefore, the answers were speculative. FERC’s NOPR can be read in detail at http://www.ferc.gov/Electric/RTO/Mrkt-Strct-comments/discussion_paper.htm#NOPR.
Inside a demand response program: Southern Company
Mike McGrath of EEI told EL&P that Southern Company has “one of the very best industrial demand response programs in the country.”
Southern Company’s Leonard Haynes gave us a peek inside:
We’re actually involved in demand response not only in the industrial market, but also in the residential market. We’ve got three types of programs we’re involved in: direct load control programs, a real-time pricing program and an interruptible program.
There are a little over 18,000 residential customers involved in direct load control, and that contributes around 40 MW of reduction. There are a little over 1700 customers that we bill on hourly pricing, and, when the prices get high, we see about a 530 MW reduction associated with customers voluntarily reducing their usage. And, then we have an interruptible program that about 225 customers are on, primarily industrial customers. When we call that interruptible load, we can get about 1900 MW off the system.
Our Alabama Power Company subsidiary has a big direct load control program, and then our Gulf Power subsidiary is just introducing a new concept for residential control called Good Sense Select that incorporates a lot of control features for the customer and also involves pricing, in that the customer can have a programmable thermostat that helps them respond to critical pricing periods. We’ve had some tests on that which look very good, and we’re hopeful that it will be a big program for us.