Analyst insight: Meeting Energy Demand

Peak load management is an important issue with power providers. Various utilities have come up with wide spectrum of peak load management programs for the industrial sector based on the dynamic pricing of electricity; however, very few utilities in the US offer dynamic retail prices for the residential sector. Next Generation Power & Energy caught up with Lisa Wood, Principal in the Brattle Group’s Electric Utility Consulting practice, to find out why this is and what the industry needs to do to meet today’s challenges.

NGPE. Utilities have recently begun to explore and implement innovative methods for managing demand. What opportunities does this focus on better demand-side management offer to electric power companies?

LW. Utilities first looked at managing demand about 15 years ago, but it never really took off then. It’s now a hot topic again, and part of the reason for this is because of the Energy Policy Act – it’s now a requirement to look at smart meters and innovative rates. There’s a huge opportunity to make the whole industry more efficient, because right now we have a lot of varying loads, and we’re building power plants to meet very small pieces of that load.

So if we can tighten up in terms of efficiency – and demand-response is one way of doing that – then we can identify gains in the existing infrastructure to help meet demand. There is certainly capacity out there that is not being totally utilized, yet we’re building power plants – gas plants primarily – to meet a very small peak. The whole idea of managing demand is to move some of that power from the peak to the off-peak periods, in order to be able to fully utilize the base load plants. And then we’re not in a situation where we’re building a plant just to meet one percent of the kilowatt-hours needed each year.

NGPE. So how can a demand response approach improve the reliability of the network?

LW. For areas that are really constrained in terms of capacity (Connecticut is a good example), demand response can basically help avoid a blackout. That’s the main consideration. In a situation where you have a very tight power supply situation, demand response can be the difference between having a blackout and not having one. And people haven’t talked about that very much when looking at the benefits of demand response – many don’t believe the value of avoiding an outage can be quantified. However, there are lots of studies looking at the value of lost load, and these studies show that there is value in avoiding lost load,. So there’s definitely a reliability value associated with demand response. The biggest benefit to demand response is capacity related – about 55 to 70 percent of the benefits are typically avoided capacity – and there are also fuel savings and T&D benefits; but the reliability benefits are there too.

NGPE. Now, you mentioned at the top of the interview that this is something that came about as a response to the Energy Act of 2005. So what kind of challenges does the power industry face in terms of implementing effective demand response programs?

LW. As a result of the Energy Policy Act, utilities have to look at demand response and time-based metering. So utilities are looking at so-called “smart” meters, and they like the idea because it has operational benefits. But in order to make these meters cost-effective, you also need dynamic pricing – in most cases, if you do a cost-benefit analysis of rolling out smart metering without a smart rate, the benefits will not necessarily exceed the costs.

Advanced metering infrastructure (AMI) meters are very sophisticated. From an operational point of view, they’re beneficial because you don’t need a meter reader anymore; all that functionality becomes electronic rather than having someone going from door-to-door and reading meters. This means that any implementation of AMI has to be rolled out in a geographic way because obviously if you just give those meters to customers on dynamic rates, you’re not saving meter reading costs if the meter reader has to go to the place next door where there is no smart meter. So utilities are looking at smart meters and saying, “Okay, if we roll these out on a geographic basis, what are the benefits and costs?” Utilities then ask what are the additional benefits associated with those meters if they were to offer a dynamic rate, or some kind of demand response program., Utilities can include both the benefits associated with dynamic rates as well as the operational benefits of the smart meters. And usually it’s about 70 percent operational benefits and 30 percent rate benefits.

NGPE. Are there any other benefits that utilities can look at from implementing AMI that might help improve that cost-benefit analysis?

LW. AMI is really useful for all the things that are not automated today – for example, if there’s a problem or an outage, utilities are currently relying on a customer to call them rather than knowing in real time what is happening with their system and where it’s happening. That’s a major benefit. It’s amazing, actually, that in this day and age utilities are often relying on a phone call from the customers to figure out when there’s an outage. The same thing goes for any sort of power problem. So in addition to the meter reading benefits, the other operational benefit is outage detection.

NGPE. I guess it’s part of the movement across industries towards better visibility into what your customers are doing, what your network’s doing, what your infrastructure’s doing and really just having better information in order to respond to that information quicker and more effectively.

LW. That’s right. We are finally moving into the 21st century! But you know, I’ll just say this: utility commissions are very reluctant for utilities to spend money unless there’s a benefit-cost test that’s been approved – primarily because utility commissions see their role as protecting consumers. And I probably shouldn’t say this, but I don’t think they realize the extent that they don’t protect consumers by the constraints that they impose in terms of flat rates. Dynamic rates are just so much more efficient; a large percentage of people can save money on a dynamic rate, and yet it’s still very hard to get a dynamic rate passed through a state commission.

NGPE. So what are your tips for getting those rates in place? Is there anything that utility commissions should maybe consider when they’re looking at these programs in terms of how to effectively roll them out with minimum cost and maximum benefit?

LW. Well, let me address the metering question first because that’s simpler. If for some reason AMI is not going to be rolled out in the entire service territory, it must be rolled out at least in geographically adjacent areas and tested in that way to make sure the benefits are there; you can test rates that way too. This is the only way it will be cost-effective. I think that’s quite easy for commissions to understand.

In terms of rates, I think the big communication failure is that flat rates have a risk premium embedded in them – on average, about 15 percent of what you pay is a risk premium just because you happen to be on a flat rate. I think the consumer should be able to have some choice. Now, some people may not want that choice, and that’s fine. For years, utilities thought residential customers would never go for real-time pricing. But there is a real-time pricing program going on right now in the Commonwealth Edison service territory in Chicago that is into the first year of implementation following a three-year pilot, and customers like it. So we need to give residential customers the option. I think there is a general view among utility regulators that dynamic rates are bad for consumers, and that flat rates are better. This mindset needs to change.

NGPE. Could aligning demand-side management with energy efficiency help prove the dollar value of dynamic pricing?

LW. I think that if you can tie any of these programs into carbon reduction or being green, it’s extremely appealing to customers. From an energy conservation perspective, we’re doing studies right now that suggest that over the next 10 years energy efficiency can actually replace much of the load growth that’s planned to happen. And energy efficiency can definitely result in carbon savings; there’s no doubt about that. But does it result in NOX and SOX savings? Maybe, maybe not. It depends on the utility, depends on what their power mix is, and it depends on what comes online and what goes offline.

Let me say something about that with respect to demand response, too. With demand response, what you’re doing is you’re shifting your load from peak to off-peak periods. Whether you get carbon benefits or environmental benefits as well depends on what your power mix looks like. If you’re in a very nuclear intensive area, you will get benefits because you’re going to have more nuclear coming online, so you will get carbon benefits. If you have old oil plants that you’re going to avoid burning, you’re going to get carbon benefits. But if you’re just going to burn more coal, you’re not going to get carbon benefits. So it really is very specific to the service area.

NGPE. Are utility AMI systems underappreciated as a vehicle for implementing new smart grid technologies? Can the AMI business case be improved by including additional operational benefits from new smart grid applications?

LW. You have to have some sort of AMI system in place. I think that the FERC has recognized that, and has pushed the state commissions to actually start to look at this; otherwise, I don’t think we’d be as far along as we are right now.

In terms of whether the business case can be improved, I think that the utilities are trying to improve the business case. There are the typical operational benefits of easier, clearer meter reading. There’s also the improved reliability you get from being able to detect an outage sooner. And then if you can hang smart rates on these smart meters, then you get all the benefits associated with the smart rates – capacity and fuel savings benefits amounting to millions of dollars plus reliability benefits.

The thing is, most people don’t even think about electricity. It’s so far down their to-do list – most customers are not going to the website and saying, “What are my electricity prices doing today?” So you have to create an awareness of the benefits of dynamic pricing, and hooking it to the environment is one way to do that; another is to create some sort of default system where you have an opt-out scenario for dynamic pricing rather than an opt-in scenario. This means that customers are automatically put onto a dynamic rate, and can choose to get off of it (i.e., opt-out), but it becomes the standard rate for that utility. If a dynamic rate becomes the standard rate, and the flat rate becomes an option, then this is one way to realize a huge percentage of the potential benefits.

NGPE. Okay, so given that the progress to date has been somewhat slow, what do you see as the key trends over the next 12-18 months to help drive smart metering, dynamic pricing, and energy efficiency forward?

LW. Well, quite a few pilots on dynamic pricing are now being rolled out. The results are coming in slowly, and as more and more of those success stories are communicated, utility commissions begin to get interested. They’re much more tuned into this than they were six, eight or 10 months ago. It’s top of mind for everybody, and I think a lot of it is getting more commissioners that are really interested in this.

We have a few commissioners now that are very pro-dynamic pricing and trying to move things along. They understand and appreciate what it is and what the benefits can be, so I think this is promising; however, we still need more people to actually advocate for these programs. There are some CEOs that believe this can be a win-win, and they’re making it happen; Peter Darbee, the CEO of PG&E is a good example, and so is James Rogers, CEO of Duke.

The trends towards energy efficiency and energy conservation mean that we’ll likely see more federal energy efficiency standards come into play, and standards are more overdue than anything else. Standards work, and that’s a quick way to do it. Regulatory incentive mechanisms are also important for utilities to promote more energy efficiency.

BIO:
Lisa Wood specializes in economic, regulatory, market, and strategic issues in the electric utility and telecommunications industries. Her practice focuses on regulatory, pricing, and market analysis issues. In the electric utility sector, she focuses on restructuring, demand response, retail markets, demand-side management, electric service reliability, and value of service.