Smart Grid at a Crossroads

Deck: 

Refining the business case for advanced  distribution investments.

Fortnightly Magazine - January 2013

When a CenterPoint Energy meter installer arrived at a customer’s home last July, he didn’t expect to have his life threatened. But that’s exactly what happened. Fifty-five year-old Thelma Taormina pulled a gun and forced the worker to abandon the service call.

CenterPoint promised legal action against Taormina. But instead of being punished, she’s achieved minor celebrity status in Texas, where she’s part of a movement to resist smart meter deployment. Local news media published a photo of Taromina looking indignant, standing next to her home’s electric meter and a sign that says “No Trespassing – No Smart Meters.”

The incident arguably marked a low point in the smart grid saga, happening in the middle of a drought for new contract awards by investor owned utilities (IOU). During the past year or so, Fortnightly has reported numerous smart grid project announcements at electric cooperatives, municipals, and other public power utilities—but very few at IOUs.

With gun-toting customers waiting in ambush, perhaps it’s no wonder. But notwithstanding the extreme responses of a few vocal opponents, the smart grid seems to have hit a dry patch in its development cycle. To learn why—and to get an idea of where we’re headed—we spoke with several experts in the field:

• Jack Azagury, Accenture Smart Grid Services;
• Kevin Cornish, Black & Veatch;
• Frits Bliek, DNV KEMA; 
• Russ Vanos, Itron; and 
• Greg Myers, Sensus.

Their comments describe an industry that’s coming out of a boom phase, and now stands at a crossroads, facing an uncertain path. But while not all paths lead inexorably forward, they do seem to be aimed at the same future destination—an intelligent network that will transform the way utilities produce and deliver energy for their customers.

Even Thelma Taormina.

How’d We Get Here?

Fortnightly: 2012 was a slow year for smart grid project announcements at IOUs, versus co-ops and public power utilities, and compared to previous years. Why?

Azagury, Accenture: Many of the smart grid projects that were announced in 2009 through early 2011 were funded by the Department of Energy, with ARRA [American Recovery and Reinvestment Act] grants. Since then, the level of activity has slowed down, for a few reasons. First, obviously we went through a boom phase with federal funding, and that boom is now gone. Decisions to cover costs for smart grid rollouts lie in the hands of state regulators. A number of states already decided to approve smart grid investments, and now we have a small trickle of states that are moving ahead. Illinois is one of them. (See “Illinois Imbroglio,” p.28) But state regulators likely will pause and look at utilities on the East Coast, Texas, Florida, and the West Coast to see if utilities in those areas get the return on investment (ROI) they expected, how the technology is working, and what lessons are being learned. That will take 12 to 24 months. After that, we’ll see more states ready to take the jump and approve investments in the smart grid.

The second thing, though, is low natural gas and power prices. Commodity prices have solved a lot of problems, in terms of pressure for demand response.

Cornish, Black & Veatch: Whenever you get a bubble like we had with smart grid deployments, after the bubble ends the industry needs to chew on those projects. If you look at just AMI, for example, with projects like those at PECO and NV Energy, those are large efforts, and are consuming for those utilities. I can’t imagine a utility like NVE, say, who’s on the tail end of a $330 million project, undertaking another large project until they get this one under their belt. So the slowdown is partly a reaction to the bubble, allowing large utilities to consume what they’ve taken on.

Also as utilities come out of these projects, utilities like Pacific Gas & Electric and San Diego Gas & Electric, they’re spending a large amount of money and focus implementing what’s arguably a foundational technology with smart metering. Now they need to decide what’s next—how they’ll leverage that investment to deliver the benefits they promised to their regulators and management, and what’s the next logical step of technology implementation, on the foundation of that investment.

That’s what we see happening now. It’s a bit more pragmatic approach than a couple of years ago, when there was some euphoria around the smart grid. Many regulators—in states like Illinois, Washington, and even here in California—now are taking a more critical view. We’ve spent billions on smart metering and other smart technologies, and regulators want to ensure they’ll get the benefits they were promised.

Installing an Itron OpenWay meter.

Vanos, Itron: While the stimulus funding was good for utilities and for the smart grid in the long run, it forced us to roll out infrastructure on a timeline that allowed utilities to get money from the DOE, or in some cases from states like California, in rate cases that were time-sensitive. That created a focus on rolling out meters, building infrastructure, and connecting it with back-office systems. It created a big blip in the curve. If you’d taken out the stimulus money, we’d have gone at a slower rate as an industry. It would’ve forced us to look more closely at the business benefits and pay more attention early on to the customer side of things.

But the good news is that a lot of smart grid projects are completed or are close to it. And as an industry we’re starting to see the benefits of smart grid technology, and we’re focusing more on the consumer side. Southern California Edison was able to get tariffs approved for critical peak pricing. They got the system connected, ran CPP pilots with customers, and achieved the peak load reduction that legislation required them to achieve. The same kind of thing is happening in Texas. It’s different because of the nature of the market, but with all the retailers selling energy, they’ve gotten creative about marketing to end consumers. It’s been remarkable to watch—and they couldn’t deliver the benefits they’re delivering without smart grid infrastructure.

We’re seeing similar benefits in Pennsylvania, with FirstEnergy and West Penn Power. State legislation said that all customers must have access to smart meters and the ability to sign up for time-of-use (TOU) rates, with customer opt-in. DR is driving a peak-load reduction program, but as utilities get those in place, they’re also beginning to see things around the grid like volt-VAR optimization. Those are early experiments, but there’s enough infrastructure in the field today that utilities are seeing benefits for both consumers and their own operations.

Myers, Sensus: We see differences between IOUs and munis or co-ops. The drivers at co-ops and munis are very operational. It’s all about reliability and the cost of the service they’re providing. For IOUs, reliability is the top focus, but it’s also about the value they can get out of hardware and wires investments. 

The stimulus funding has been pretty much used up, and we’re still seeing the IOU market primarily driven by PUC funding—projects based on regulatory drivers. We’re still looking toward a full AMI deployment, it just isn’t happening as quickly, en masse, as it was over the past five years.

Bliek, DNV KEMA: There’s a different perspective between U.S. and European markets. In Europe, we have an average downtime on the electric grid of 30 minutes a year, and for gas it’s 2 minutes. In the U.S., there seems to be larger blackouts and they last longer, so there’s more tension in the U.S. to implement solutions for here and now, today, rather than looking too far ahead. In Europe there’s more of a forward view, to develop solutions for tomorrow.

Also in Europe gas prices aren’t really affecting the discussion. And we’ve had a number of very large projects, with success stories that accelerated the market. One example is the rollout in Italy, which had a significant collection issue, with a lot of clients who didn’t pay bills or who never even got a bill because meter readings weren’t available. That made it an easy business case. A few other examples are showing that smart meters are beneficial to the whole energy system.

As I look at where we are today, you see that while smart meters are there, along with technologies to do all types of business, the real business model behind it is lacking. In the U.S. it’s driven by gas and electricity prices. But still, in Europe there’s a tendency to start developing energy management portals that you can access over your iPad or mobile phone to get information, but when you really try to deploy that, there’s no clear business model behind it. The value proposition for the end user is a variable at this point in time.

Installing a wireless antenna for the Sensus network at Talquin Electric Co-op.

From the utility perspective, a number of solutions seem to work—mostly involving direct control of the end device, switching off the customer’s AC when the rates are too high. That’s an ideal solution for preventing damage to the system, but it’s not really adding value for the end user. The industry is still looking for solutions.

 

Refining the Business Case
DC PSC RFP Technical Consultant for Formal Case (FC) No. 1156

Fortnightly: What’s next for the smart grid? How is the business case evolving for IOUs?

Myers: For customers who talk to us about distribution automation, reliability is a big driver, and they’re also looking at optimizing their delivery system, so they can run it to deliver the best service they possibly can, and can accomplish things like conservation voltage reduction.

Moving forward, we’ll see utilities putting together business cases based just on automating meter endpoints, for those that aren’t already automated. A lot of utilities that rolled out AMI are seeing substantial savings from fewer truck rolls for disconnect and reconnect, and they’re seeing advantages in prepayment applications, as well as distribution automation and outage management. Utilities that have deployed our networks have been able to cut service restoration times by an astronomical amount. A powerful story is Tuscaloosa, Ala., where they were able to bring everything back up and restore power quickly after the tornadoes rolled through.

As these things take hold—as utilities monetize these benefits—it will strengthen the business case for building advanced distribution networks. We’re just entering the realm where utilities aren’t just focused on getting the cash register working right.

Vanos: We’re in an era where we’re working closely with utilities to architect a solution to fit their needs, to address their specific problems. It’s about partnership.

The solution is different from one utility to another. For utilities that rolled out meters across the system, like Southern California Edison and SDG&E, the plan is to take advantage of all of that in the next couple of years. For companies that didn’t saturate, like Duke Energy in Charlotte, what’s next is to install several hundred thousand meters. But because there’s no longer stimulus money—and except for in Pennsylvania there aren’t state mandates for AMI or TOU pricing—everyone is looking at the basics—what it takes to run the utility. We’ve got plenty of energy right now, with lower demand and low-cost natural gas, so utilities are making investments to solve operational problems. The big thing we hear now is the need to be flexible and future-proof. That translates into IPv6 [Internet protocol v.6], analytics, distribution automation, back-office systems, and a consumer-side focus.

Talquin Electric Cooperative’s dispatch center incorporates data from a Sensus FlexNet network.

You’ll see lots of smaller deployments, not nearly as many big deals as we saw a few years ago. These deployments are more surgical and strategic in nature, solving specific problems. But while they’re looking to fix an operational problem, they’re also looking to make sure the technology is flexible and allows them to turn on additional features.

Cornish: NV Energy is a good example of a utility taking the next steps, with a rigorous eye on the business case. NV Energy has installed about 1.2 million meters, and now they’re looking at how to leverage that foundation to implement outage management, and to get more rigorous with DR and customer engagement, looking at what truly is the business case for that.

When the project was first envisioned five years ago, the economy was stronger and capacity issues were more pronounced around the country. A lot of smart grid investments were justified, in part, by the ability to shift or reduce peak demand, or to support a higher penetration of renewable energy. Now if you look around, most of the country doesn’t have a capacity problem—including Nevada, and also California, where the business case relied on propping up operational savings with demand response and efficiency savings. There’s no business case anymore for smart metering if it’s just to shift demand, at least not in the near term. As the market has changed, many utilities are trying to reset that business case. That’s a real challenge.

But the other part of the smart grid is the need to upgrade distribution infrastructure overall. The challenge there is that spending capital on infrastructure tends to directly hit the bottom line, in terms of electricity rates. From a utility perspective, they’ve always been happy to spend capital for a rate of return, but today regulators are loath to allow rate increases and investments in the rate base. Utilities don’t want to take the risk that something will be deemed not prudent, and they won’t get rate recovery. That’s slowing down that investment. Plus East Coast utilities have spent significant dollars on storm restoration, and frankly they don’t have the money to embark on large smart grid infrastructure projects—unless regulators will allow a rate increase.

Azagury: The focus is shifting. Discussions with clients now tend to focus on grid operations—specifically, packaged distribution management solutions, integrated with core systems, including metering and work management. The objective is to gain broader visibility and management control over the distribution grid, and to optimize it. The second area of focus is analytics. We’re at the early stages, and there’s a lot of hype, but the hype will give way to analytics becoming mainstream. That’s happened in other industries; at financial services firms, retail companies—even in the defense industry—analytics is just the way they operate. There’s no hype, it’s just what they do. It’s a core competency for daily operations. Utilities are going through that transition now, and it’s important because all the companies that have deployed smart metering are now looking at the data and seeing how valuable the information is. They realize they need IT in place to use the data to drive business results.

It’s a technology problem because you’re pulling data from many systems—real-time systems, with structured and unstructured data. Companies are tackling this with just a few use cases at a time, and when they do, they see payback. It’s outage analytics, grid operations analytics, theft analytics, and analytics related to distributed solar PV. Different companies are tackling different use cases in different orders; it’s not a problem that you can tackle in one fell swoop. But when you tackle it one use case at a time, you eventually get a big picture and you industrialize it. To me, that’s grid operations with an analytics layer on top of it, using smart grid data. That’s where the utility is going. It’s not a fad, it’s mainstream.

That’s the transition we’re seeing. What happens next depends on the outcomes of projects in the industry today.

Bliek: The initial thought was that smart meters would allow energy markets to open up, with the introduction of things like time-of-use pricing and energy management systems. That’s been hampered by privacy and security questions around smart meter data. In principle it’s a very small group of end users who don’t feel good about what’s happening with smart meters, and that directly relates to other variables—such as people entering the home to install a smart meter, and apparently giving nothing in added value. The consumer thinks, “Now I have a smart meter, and the utility reads it remotely. What’s in it for me?” That situation has improved, but still people aren’t willing to let someone else take control of their data, and so rollouts are delayed because the value created isn’t yet shared with the end user.

Black & Veatch managed a smart grid project for the Fort Collins, Colo., municipal utility.

At the same time, we see ambitions to build large-scale demonstration projects of smart energy systems. We see this happening worldwide. A lot of them are focused on smart meters—too much on a single solution, and not integrating everything together. So the next step is tying up all the angles to achieve strategic decisions and plan for a full-scale rollout.

It will take a few years to go through all that. Along the way opportunities are emerging for power balancing—attaching the supply side to the demand side, bringing the end user into the market, and introducing real current prices for congestion on the networks. Allowing end users to self-generate power will take a few more years, because we need to agree on a future business model for the energy system, and to agree on the new rules.


Think Global, Act Local

Fortnightly: Given what we’ve come through, what’s the long-term outlook for the smart grid? Where do you see market opportunities emerging?

Azagury: Over time it will go mainstream, away from the hype and the bubble. It will become part of day-to-day business. It’s just the way we invest in our grid.

Also we’re seeing a lot of global activity around smart metering and the smart grid generally. The same type of activity we saw in the U.S. in 2009, we’re now seeing in the EU, Japan, and other countries in Asia. Debate is happening in some countries in South America. I’m in Singapore today talking about the smart grid. I was in Japan earlier this week, meeting with utility clients there. The biggest utilities have started, and others will follow. They’re going through a very rapid deployment. There’s a huge impetus for DR and efficiency, and a tremendous amount of activity.

Cornish: If you look at the work a couple of utilities have done, it implies some new models for the way companies provide outage information to customers. We’ll see a much richer web portal, where you can drill down into maps for information specific to your area or your account, and you can get it from your smart phone.

The challenge that utilities face is that they’re behind most other industries, because information about outages and maintenance, etc., has a very internal focus and it doesn’t reside in a single utility system. It might be in three or four different operational systems, and no single utility person has a complete view of what’s going on. Taking all of that information and packing it for end-use customers has been a big challenge, because the first thing a utility must do is get a handle on what’s going on internally. Any information you provide will generate follow-up calls and discussions, and you don’t want the consumer to have more information than your CSR has. It will require a fair amount of technology integration and back-office work, with refined outage management systems and geospatial information systems, to make that information available.

ComEd serves as a good example with the work they’ve done over the past couple of years in this area. Poor storm response a couple of years ago pushed them along that path, and we’re seeing the same thing on the East Coast, not just with Superstorm Sandy but also Hurricane Irene a couple of years ago. In those cases, unusual weather patterns caught utilities flat-footed. They didn’t know how many customers were out, or where they were out. Regulators and the news media crucified them, and it created a sense that specific to outage management, utilities need to communicate better with customers.

Myers: We’re pretty bullish on what we’re delivering. Instead of layering multiple networks, we’re running multiple applications through the FlexNet network, and expanding on applications that our customers can use—both new and existing customers. Examples include distribution automation and DR. To do this we’ve continued to expand our spectrum. When our network was first released, it was very much an AMI and meter-reading kind of network. But with the ability to add spectrum and to channelize the data within it, we’re able to do applications that require time-sensitive communications and the ability to handle more data.

Bliek: If you look a few years out, you get into a distributed generation model where customers are also suppliers. You can see a situation where there’s a large rollout of solar, plus micro CHP [combined heat and power], heat pumps, and electric vehicles coming into the market in huge numbers. These will all become part of the smart energy system.

Today you see this in Europe, but there are some examples in the U.S. as well. In Denmark, about 50 percent of power production comes from renewables. In the Netherlands, about 25 percent of power is generated by CHP at greenhouse farms and industrial sites. Germany has 22 GW of solar power installed, almost equal to the total power production of the Netherlands. Very huge amounts of distributed and renewable energy sources have come into the market, and they’re in the hands of different people. There’s a business case to make their generation a part of the system, and there are major societal benefits, whether it’s fossil fuel based or even completely renewable. It requires an updated grid, but in either scenario, the smart grid adds value.

One of the important drivers is the introduction of DR. Everyone thought that installing smart meters would make it simple to enable DR, and in principle that’s still the case. But it requires allowing customers to partner in energy markets. To create value for residential end users, they need to be partners in the market.

There’s huge potential in DR, if you have the protocols in place, and the technology is commoditized. The big semiconductor manufacturers need to be part of the transition, so they can bring the technology costs [of appliance intelligence] down to a few Euros.

DC PSC RFP Technical Consultant for Formal Case (FC) No. 1156

Industrial customers already are using DR and actively trading on the energy markets. At greenhouse farms, cooling loads are flexibly integrated. That value proposition is effective in the market. That same scenario will be beneficial in the U.S. too, even though gas and electricity prices are low today.

Vanos: Microgrids represent a great opportunity to become energy independent in the future. You can’t do microgrids without having an intelligent network, with the ability to measure both ways what’s going in and out, whether it’s at a feeder, a transformer, or a home. Whether the generation is renewable or not, we can solve a lot of real-life problems if we have a smart grid installed to manage microgrids.

This could be a reality here and now if we decide we want it. In fact Hawaii already operates very much as a renewable microgrid. It’s expansive across the island of Oahu. But Manhattan also has the same characteristics; there are real steps we could take today to improve energy efficiency and reduce dependency in Manhattan. They’re rebuilding the grid in New York. They should be installing microgrids. Microgrids can play a role today, but they’ll always be over the horizon if we don’t implement smart grid technology.

In California, Texas, and New England, you’ll see microgrids immediately. It’s just a matter of cost-benefit. As a company, Itron is spending more time in this area. We’re interested in how to support microgrids from a technology perspective, and as a growth business for the future.