Case Study Interview: ENBALA

Presented by the Association for Demand Response and Smart Grid

 

National Action Plan on Demand Response (NAP)

Case Study Interview

 

ENBALA - Ron Dizy

April 24, 2020

Dan:  Welcome. I’m the Executive Director of the Association for Demand Response and Smart Grid, also known as ADS. We’re an
organization that is working to implement the National Action Plan on Demand Response.

Quick background on the Plan: It comes about as result of congressional direction back in the Energy Independence and Security Act of 2007, which instructed DOE and FERC to develop and release such a plan. One of the needs of the demand response community that was identified as the plan was developed, was the documentation of lessons learned by individuals, companies, and organizations that were involved with demand response programs and other activities. There was identified a great desire by those people to know what kind of things their counterparts elsewhere had identified, whether they be pitfalls or best practices. With the help of the Department of Energy, ADS is working to identify and document lessons learned as part of the implementation of the Plan.

So what is a Case Study Interview? A lot of you know that a case study normally involves examining a project or program and presenting results and observations. A few case studies tend to focus on really telling the story of what happened in that project or program. In an ADS case study interview, the story is our emphasis. We want to let people who are involved in development of programs talk about how things went, and reveal their lessons learned.

Today, we’re going to be talking with Ron Dizy. He’s the Executive Vice President and Chief Revenue Officer of ENBALA, and the focus of our discussion is going to be the real-time integration of intermittent wind power through a network of demand-side loads with New Brunswick Power in Eastern Canada. Welcome, Ron.

Ron: Thank you. Happy to be here, Dan.

Dan: Thanks. I wonder, Ron, if you could begin by telling us a little bit about ENBALA, and then we’ll dive into the project.

Ron: We think of ENBALA as a smart grid technology company. We have built, and we sell and we operate, a smart grid demand management platform that is capable of connecting to customer loads in real time, and managing them in such a way to provide grid services back to any grid operator. We do this for PJM, where we supply frequency regulation from a network of loads, and we’ll talk a lot today about how we’re using that exact technology platform to supply wind integration for New Brunswick Power.

Dan: All right, well thanks. As I already said, you’re going to be telling us about this specific project, and let’s first talk a little bit about that project, and what type of project it is.

Ron: New Brunswick Power was the lead proponent for a larger project called Power Shift Atlantic. The idea behind Power Shift Atlantic, it was partly federally-supported by the government of Canada. The idea was to demonstrate the role that the demand side could play in the integration of wind into the power system. New Brunswick has since thought of it as part of a bigger program that they called RASD, Reduce and Shift Demand, which they see as key to managing the costs into the future of their power system.

Dan: How did this project come about? Why was it begun? Why was it needed?

Ron: New Brunswick had a broad view. New Brunswick has about 300 megawatts of wind in a system that troughs at about 1,200 megawatts and has a peak of 2,200 megawatts. What they found was, integrating that wind, particularly during the shoulder periods, meant they had to run fossil plants, and in their case oil plants, at minimum load. And so they found, like many jurisdictions do, that the process of adding renewables didn’t really have the impact on greenhouse gas emissions that they wanted. It was expensive, so they were looking for a better way to integrate wind, and were looking to real-time demand management technologies to figure out if they could actually do it with that. That was the driver for it.

Power Shift Atlantic, again, became a demonstration project to prove that this could work at scale. There’s almost 20 megawatts of controllable load in a variety of applications now as part of this project, and then demonstrating you really can manage load at reasonable scale to deliver the sort of flexibility that is needed to integrate renewables into a power system, even when those renewables are a fairly substantial part of the power system.

Dan: Ron, when you say, ‘controllable load,’ is that another phrase for a demand response, or are you trying to be more specific about something as you say that?

Ron: Yeah, I think ‘demand response’ is a good catchall word. I think the challenge we’ve often found is that demand response often means curtailing loads during hot days in the summer a few times a year. I think grid operators use the phrase, ‘demand response’ correctly, and to me it means anything load can do, or anything a customer load can do to respond to the needs of the grid.

New Brunswick was clearly looking for something that they could call on more or less continuously, and that has some pretty major implications for how that load will need to be controlled. We use the term ‘controllable load’ because we’re going to try to access that load, or influence its consumption, in this case every 15 minutes, so literally four times an hour adjust how much power load is consuming in order to better balance renewables. It is absolutely demand response, but it’s on a scale much different than I think most of us are used to.

Dan: It’s my understanding that the wind blows at different times, in different amounts in different parts of the continent. I’m wondering, when does it blow in New Brunswick, and what does that mean for the system up there?

Ron: New Brunswick is part of the Maritime Provinces, and so a lot of the windmills are actually coastally located. I think their experience is that the wind tends to blow more at night, and the biggest challenge they would experience is when the wind is blowing at night, and then they might lose it during the morning ramp. You are ramping the system to meet daytime need; wind is part of that supply mix, and if that wind suddenly goes away, it’s very challenging for the system operator to replace the wind while also adding new generation to match the morning ramp. That’s a good example of a particular grid problem that arises when wind is a decent chunk of your generation, as much as 25 percent as I say, if the wind is all blowing at trough.

Really, what they were trying to do is find a way to integrate that wind in a more, in a cheaper, more constructive way than simply by backing it up with a fossil plant, which would, of course, be the traditional approach.

Dan: I’ve sometimes heard the phrase used ‘intermittent renewables,’ and I guess especially wind, and demand response sort of were marriage partners in trying to make sure there’s always a resource, one or the other. Is that kind of what’s going on here?

Ron: Absolutely. I think that’s right. I think many people have thought of the idea of saying, well if we can have demand react to a hot day in the summer, why not have it react to loss of wind at a particular time? I think notionally those ideas are right. What changes, if you’re trying to use demand response or real-time demand management to integrate wind, is how often I’m going to call on it. It’s not something I'm calling upon only occasionally and where it’s okay to be disruptive to the load, right? Which is kind of how we think of demand response today.

Here we’re going to ask you to stop using for four hours on hot days in the summer, but it’ll only happen five or six times, and here’s some compensation for that. Now we’re talking about something that we might want to use every day, even multiple times in a day. How I connect to that load- I introduce the notion that I have to be continuously connected; I introduce the notion that I’m going to call on the load far more often. That, of course, has pretty profound implications for the impact that I can possibly have on the load, and make that a reasonable experience for the load.

Dan: I think what we’re talking about here may go into what some of the goals for the program were, and so why don’t we talk about that.

Ron: Sure. The goal for the program, for New Brunswick, was to demonstrate that this was feasible. We’ve got this big-picture idea. Could customer load actually be able to react and supply this? They wanted to show it in more than a few‑hundred kilowatt demonstration project; they wanted to show it across a range of their customer base in a range of different applications. We, of course, wanted to demonstrate that our platform could be a key part of that.

Our real-time demand-management platform was specifically designed to connect commercial and industrial loads. In other parts of the project, New Brunswick actually connected residential thermal loads, so hot water heaters and even thermal storage for inside houses. New Brunswick has a fair penetration of electric heating for both hot water and even space, because it’s a province that does not have an extensive natural gas infrastructure. There’s a real opportunity there to manage electrical use that’s used for heating as well.

Our particular part of the project, ENBALA’s, was focused on larger commercial and industrial loads and see if we could capture what we call inherent process storage, the idea that there’s already storage in the grid, it’s in the form of water in reservoirs and cold-storage facilities and even the thermal mass of buildings. The idea is if we could capture that storage, we can make it available to do things like integrate wind.

For the customers, New Brunswick took a very interesting approach, and it was to engage their customers in a way that said, “Help us make the grid better,” and that was the primary driver for participation. We want to integrate wind in a way that doesn’t require us to back it up with a fossil plant. It was amazing to me to see how their customers rallied to that. They were proud to be part of Power Shift. It wasn’t about economics; it was about helping the grid perform better. I think New Brunswick Power did an amazing job.

I think this is often an undervalued part of demand response programs; we tend to go to, “How much will you pay me?” We found that New Brunswick, at least, did a fantastic job of engaging the customer to be part of the solution, and the customers wanted to do that.

Dan: They liked feeling that there was more than just money at stake, in terms of their participation.

Ron: That’s right. I think of it as like recycling. We don’t pay you to recycle, but if you make it easy enough, and you make it non-impactful enough, people are willing to do it because it’s the right thing to do. We think we found the same thing with this.

Dan: You’ve already been talking in the past tense here, which leads me to believe that this project has been under way.

Ron: That’s right. The RFP for the pieces of what they call the aggregator program, so the technology required to connect customer loads to what they called a VPP, the system that would provide the signal to say, “Okay, wind is- what do we want the demand response to be?” They use the term VPP to describe the software. That had been under way since, I think, 2011. We won the RFP in early 2012, signed a contract by the spring of 2012, and we actually had the first loads live on the system by the fall of 2012. It’s now been operating for, I guess, coming on two years in September.

Their goal is to continue operating, continue gaining experience with the performance of it, as they consider how to do a broader rollout, and what other grid services they might want to capture from these real-time connected loads. It’s another huge benefit, right? Once I’ve got customers connected in real time, sure, we’ve talked about how do we use it to integrate wind, but what else could we do in terms of grid services? New Brunswick is thinking about the bigger package of, how do I engage customers to participate in the grid? I think they’ve had a great experience with asking customers for their help, and customers being willing to participate.

Dan: Ron, I’m less familiar with the governmental and regulatory system at the provincial level in Canada than I am at the state level in the US. What kind of regulatory approval was needed?

Ron: New Brunswick is what we sometimes call a vertically-integrated utility. It means it is technically owned by the Province of New Brunswick, and it is a utility that owns its own generation, its own transmission, its own distribution, and it operates itself. It has relationships with Quebec, with Nova Scotia, and with some of the New England states, where they would trade power, but it’s its own entity.

It does report to a provincial regulator, and this particular project would have had the regulator say, “Yes, we’re willing to spend some money to demonstrate this.” That part of the project was done before we became involved, and as I say, it was matched by a funding grant, not unlike the ARRA smart grid grants that happened in the US, from a federal agency called NRCan, Natural Resources Canada, that actually paid about half the cost of running the project.

Dan: You got the bid, won the bid, and you began to design and develop this project. What were some of the things that you ended up facing, and how did you deal with them?

Ron: They had created a high-level technical architecture for us to work within. They created- when you think about, what do you have to do, there’s clearly an execution layer. So how are we going to get customer loads to react when we want them to, and that’s really what our bid was for, what we call our platform, the GOFlex platform, that stands for Grid Operating Flexibility.

We needed to integrate, then, with a control signal. Something had to tell us what we wanted the loads to do every 15 minutes, was the timing that we decided on for this project, or New Brunswick decided on for the project. As I think I mentioned earlier, they built what they call a VPP, a Virtual Power Plant, to make the decisions around what would we like loads to do. That wasn’t part of our project; that was something that New Brunswick engaged other contractors to provide.

What the VPP does is, it takes real-time demand information, so we supply that. We are constantly monitoring the customer loads, and we’re supplying information to the VPP about what is load right now, and also what’s our best estimate of what load will be. Because we understand these customer loads as well as we do, when we connect them, we can both understand what they are right now and what we would expect them to be in 15 minutes, and an hour, and three hours.

In addition, the VPP takes information about current wind, and it also takes information about wind forecasts. They worked with the University of New Brunswick, with some academics actually, to develop some algorithms to take measurements and make predictions on wind. You’ve now got current load, projected load, current wind, projected wind. With that, they could make a decision on, right now, if we forecast that load is going to continue to go up and we think that wind might go down, for example, the VPP might well make a decision that says, it would be best if we had load consume more power right now, so that it can consume less power later, when we expect to have a wind event. That might be an example. That effect would tend to mitigate the problem of losing wind at an inopportune time, like during the morning ramp.

In the design phase, we were faced with the challenge of, how do we integrate with the VPP? What sort of language are we talking, what does it mean to provide a demand forecast? Everything from, what are you really asking us for, to what will the formats be for how we’re going to share that information. The VPP, because they’re dealing with not just us an aggregator, we were the commercial and industrial aggregator, but there were residential ones for the residential energy storage as well. How does all that come together in the VPP as it makes decisions by what they call these load classes? They might make different decisions about what to do with different load classes.

Dan: I was going to ask you about that. Here you’re teaming with a utility, and it’s the utility’s customers that you’re seeking to implement load control with, and so the utility has information about its customers, which they’re able to supply to you, which helps you do your job.

Ron: That’s right, and that was very much a two-way street. In fact, ENBALA has a fair amount of expertise in what we call load targeting. How do we go and look for loads that are likely to have flexibility, or are likely to be reasonably easy to connect to? This is earned through our work in PJM supplying frequency regulation, but also on some work we’ve done in the past with Oak Ridge National Lab and the DOE, in trying to quantify the amount of flexibility in the grid.

We brought that information to New Brunswick to say, this is where we think we should look. New Brunswick would say, okay, we have those sort of loads here. We helped them a little bit with the, how should you approach customers? What are the likely questions and objections going to be? And work with New Brunswick to make sure that that was an easy process for them to attract loads and some things like, how would you contract for something like that?

At the end of the day, the customers signed contracts with New Brunswick, not with us. We provided enablement services to New Brunswick to help them onboard those customers.

Dan: You’ve referred to other companies that, I guess, were assigned other projects as part of this larger project that New Brunswick was implementing. Did that mean a lot more coordination for you and your project with those other ones, or were you able to keep your head down and do what you needed to do to succeed in your part of the project?

Ron: We really were able to keep our heads down. There was a strong view that different load classes, and that’s the term we used, are just different. The characteristics you’ll get from a hot water heater, for example, the sort of storage it has, and its durations, and when it’s likely to be available and when it’s not likely to be available, are just not the same as commercial and industrial loads.

It was one of the core concepts behind the design of the VPP, the Virtual Power Plant, that was this idea that different load classes would have different capabilities over different times of the day, and the VPP would actually try to make decisions to use those load classes in the best way possible.

For example, domestic hot water heating, you don’t want to be playing with that between six and eight in the morning, exactly when people are using it. Many of the commercial and industrial loads are available at that time. Really, New Brunswick, the project leaders handled a lot of that and allowed us as aggregators and suppliers to focus on our part of the world.

Dan: This is a case of where you’re sort of like a power plant now on the New Brunswick system, and at some point do they take it over and do it, or are you always going to be there?

Ron: It’s certainly contemplated in the contracting that eventually they would take over operation of it. So when we implement a system like this, we charge a license fee for our GOFlex platform. We are paid to help them onboard loads. We are continuing to be the operator of the platform, so it’s real-time software that has to be continuously monitored. The site connections have to be continuously monitored to assure they’re up.

Any time you touch customer load, if something goes wrong, you may well get phone calls, so there’s a customer-service function to make sure that nothing we’re doing is having any negative impact on the load. It never is, by the way, but it doesn’t matter; as soon as you’ve touched the customer and anything goes wrong, they think about the person who came in and touched something. All those things are still functions that we are carrying, and we’ll continue to, for at least another year.

Over the longer run, New Brunswick will have to make a decision as to whether or not they want to internalize this, train their own staff, bring the software in‑house. It’s certainly part of our model to be able to do that, and I think the jury’s still out on whether or not they say, “We could do that,” or, “You know what, why would we? It’s not core to what we do. We’re happy to have ENBALA as an outside supplier, they’re doing a great job at it, and why not let them continue to do it?” We’ll see how that turns out. It’s contemplated that they would be able to bring it in-house and certainly, our license fee is flexible enough to support that model.

Dan:  That’s an interesting area of contemplation, and it could be for discussion as well, given that I think utilities around the world are starting to think more about that question: what do they want to do themselves, versus what do they want to contract out for. We’ll save that for another interview.

Ron: You’re right, that is a whole other interview.

Dan: Let’s move on and talk a little bit about the technology, and you’ve done some of that already. Without going into product promotion here, tell us about, and again, with focus on lessons learned here, and some of the choices that you made, and some of the deployment choices as well.

Ron: Sure. A very brief thing on just how it works. When we connect to a customer, we install what we call an LCP, a Local Communications Panel. That panel integrates with the customer’s existing BMS/BOS, Building Management System or Building Operating System, or SCADA. It connects through conventional modbus or BACnet-type interfaces, and that leads to the first lesson, which is, we have found it’s crucial to use the existing automation platform at the customer, because they’ve already invested and they already trust it.

If we can provide that interface, it actually does two things: it give the customer confidence that we’re not doing anything outside of what they would already be comfortable with, and the second thing it provides is access to a wider range of potential equipment to be put under control. Instead of connecting directly to a chiller or a fan, we can connect once to the BMS, and now have access to the full range of devices that might be able to exhibit some flexibility. That was a key lesson.

The platform is continuous in real time, so the second thing we had to do, and a key lesson is, how do you create an easy language for the customer to understand, in terms of defining what we call constraints? Coming back to the things we talked about at the beginning, the profound difference between doing something where you’re continuously connected to the customer, and you’re trying to supply a grid service four times an hour, instead of four times a year, that now means we have to be non-impactful to the customer. We have to find ways to capture flexibility that’s there, but without them actually knowing it’s happening.

To do that, we have to go to the customer and say, “So tell us what flexibility means to you.” Most customers don’t understand that question. They say, “We don’t really have any flexibility. We just turn it on and run it.” It is important to create a language the customer is able to understand.

In reality, your building space- remember, this is in Canada, so your building spaces will be between 19 and 21 degrees, or 19 and 22 degrees Centigrade. That is your actual range, and the machines that are powering that, the fans and the compressors and the chillers, you’ll have some sort of duty cycle you’re okay with in terms of them being turned on and off, maybe five times or ten times an hour. You will have some sort of those constraints, so creating a language for the customer to be able to explain that was a key part of it.

Getting fast at capturing information about what was on at sites, you learn that no building is actually well-documented. We found in almost every case there was additional equipment on the BMS that was never documented, or a bunch of things that they thought were connected to the BMS that weren’t any more, they were old. Learning how to identify that sort of thing quickly, so that we didn’t- we weren’t wondering why the response wasn’t what we expected it to be. I think those are all key lessons learned in the process, and I think we got pretty good at it.

We really found that by the end of it, customers were onboarded much more quickly at probably half the cost of the early ones. We learned some things around connecting once to a network of schools, for example, and taking advantage of pre-existing communications to those schools. There’s a bunch of learnings on how do you do this more cost-effectively, faster, and cheaper. We got down to four to five weeks to connect a customer when it was taking three to four months at the beginning.

Lots of positive lessons. At the end of it, we ended up with almost 2,000 devices connected across 150 customer assets, across multiple megawatts. You certainly get better with it over time.

Dan: If I heard you right, you talked about connecting to the existing systems, and is that Building Management Systems? Am I saying the right thing here?

Ron: Exactly. Exactly right.

Dan: But aren’t some of those existing systems not new enough, or sophisticated enough to really handle the kind of thing that you need to do, to fulfill the New Brunswick goal?

Ron: We found that the vast majority were, actually. You certainly ran into some that weren’t, but most of them were. BACnet has been a standard, for example, that’s been around long enough that most systems still support it. We also found that if some vendor had been successful in the past, and actually had a super-majority of the BMS systems, once you connected to that vein of customer, we found that there was more than one that was similar, that also helped with efficiency in the process.

Dan: Let’s turn back to the customer, whom we talked about a little bit about before. It intrigued me earlier what you said about the idea that the customers, this wasn’t just about saving energy, but this was about bringing renewable energy to the province?

Ron: Right. Or a better way to integrate the renewable energy that they have.

Dan: What else, as you think back about marketing and promoting and doing outreach to customers, and recruitment of those customers, were the lessons learned, if there’s anything else to add on that?

Ron: I don’t know if there’s too much more. Again, I’ve said that I thought New Brunswick Power did a great job. I think the lesson they would have, they’d just say this was one of those things that we did right. We spent, New Brunswick Power speaking, spent a lot of time and effort up front on what the messaging should be, and spent a reasonable share of the spending on this project, was, I think was very intelligently, focused on conveying that message to the customer.

There was a lot of outreach done to municipalities, etc, by New Brunswick Power saying, “This is what we’re trying to do, this is what we’re trying to achieve.” Again, what’s fascinating to me is they focused on the outcome of the project rather than what was in it for each individual person, and were very successful with attracting customers, without paying them to participate in a program. They said their lesson learned would be, we found that we really could get customers to participate in the greater good if it was not impactful to them.

Remember, it’s different than traditional DR. Customers would say, “We don’t even know it’s operating. We understand that New Brunswick is capturing inherent flexibility, but it’s not impactful to us. We’ll do this because it’s the right thing to do, and we like the idea of helping the grid.” I think New Brunswick is trading on the fact that they are well respected and have a good reputation among their customers.

I think it’s a great lesson for utilities. We tend to go to this, we’ve got to pay people, what’s in it for them. I think we tend to undervalue, in general in the sector, the notion that people will generally want to do the right thing if we can make it easy for them. New Brunswick did a great job of making it easy for them.

Dan: That’s great to hear. In terms of ENBALA and what you had to do, and without revealing any internal secrets, was there anything that turned out to be the more challenging part of it, or is more of a new discipline that hasn’t been there before?

Ron: Yeah. The controls and project management, etc, were all based out of Toronto. Our NOC and our software development team is based in Vancouver. New Brunswick is a two-hour flight away from Toronto.

What became very important to us, and frankly, important to New Brunswick, was the idea of using local contractors to do as much of the work as possible. I think our team did a really good job of separating out, contracting out, as much of the work locally as we possibly could. That was a good decision for two reasons. One, New Brunswick found it was a good thing, because it created jobs in the province, and that was important to them as part of this project as well. It was important to us because we had local contractors the customers knew and trusted, and we could focus on what we viewed was the higher value elements of the engineering.

Controls, engineering strategies, understanding how the loads would need to be connected, understanding mechanical engineering components of what we would be doing to equipment, but local contractors were the ones who implemented all that. I think our team did a good job of using technology to be connected and be available.

I can remember going to one meeting with New Brunswick Power and they literally thought that our project manager had moved to New Brunswick. He didn’t; he didn’t even go there that often, but there was an effective use of technology to stay in contact all the time, and it was, maybe, a good example of combining remote work with local work in a way that really worked for everybody.

Dan: You’ve talked about some of the changes that were made along the way as we dealt with each of these areas. I think what I’d like to do is do a little look back and then look forward here. Let’s talk about surprises. What surprised you, and what did you do about it?

Ron: I think I highlighted this, but it’s worth highlighting again. I don’t think we appreciated just how little most facilities managers know about their own equipment.

They grow organically, and they’re just not even aware of things that are connected or that are no longer connected to their BMS or SCADA. Equipment’s been upgraded, and it simply doesn’t get documented, and it’s not always then implemented into the Building Management System, which means it’s not even under control. Which can have some pretty profound implications for energy efficiency. Things are now operating outside the BMS, and they’re not even reported upon.

What we did about that is, the way we did site audits changed. We tried to identify challenges like that faster, because if you’re not even seeing it, it’s very difficult, of course, to understand impact. We started changing how we did site audits to identify those things faster. That did two things. It made us better at understanding the equipment at a site, obviously, but the second thing it did is, the customers were generally happy to find- wow! I always wondered why that thing was always running when I walked by it, now I realize it’s because it wasn’t under control.

We actually had the additional effect of in many, many of the buildings we worked with, of identifying energy efficiency opportunities, often just by tuning the BMS a little bit. That was a good plus, and it’s something that we’ve started to incorporate back into our value proposition as we think about real-time demand management for customers. Because the process of connecting those customers is more intensive than it is with conventional DR, it also uncovers tremendous opportunities in EE. We start talking more about the idea of integrating EE with DR. In the implementation part of that, I think there are some profound opportunities.

Dan: You’ve talked about one of the key takeaways as being the work with the customer. Early work, and close work, and making them content. I think we understand that, but let’s go to the general question of, what would you have done differently if you had it to do over again?

Ron: We tend to do this now. The idea of focusing only on the energy-consuming equipment that’s already integrated with the BAS or BMS, if we’re going to try and add something else to it, that usually takes longer than we’re willing to spend time on. What we found was, it was better to say, if you do have additional equipment, and yes, it probably should now be connected to the BAS/BMS, you’re better off saying, “Let’s not do that first. Let’s work with the stuff you already have connected and we’ll come back to that later if we have time.”

In general, too, and we did this pretty well at New Brunswick, the local communications panel is an industrial computer. It is smart enough to be able to capture the constraints. To the extent we don’t have to do the work twice, put constraints in the local communications panel and also in the BMS/BAS, of course, you’re not doing dual work. In general, we were able to do that through most of the New Brunswick projects. Maybe only things like water plants get the belt/suspenders approach. That worked well.

Sometimes you just have to come up with a building and say, look this BAS is just going to be too hard to interface to, it’s too old. We found it’s probably better to cut your losses early than try to find a way to MacGyver a connection. There’s always another load to consider. Again, you can always go back to those. I think creating standards around, these are the kinds of loads we will connect, and then if it doesn’t have a Building Management System that supports at least some level of BACnet, for example, we just choose not to spend the time and money on it, because it tends to increase the overall cost of connecting. Those were all things we wanted to learn, as part of this project.

Dan: As we move towards wrap-up here, let’s flip things around and look forward. Again, this was alluded to earlier in terms of how the utility industry is going to evolve and so on. How do you see ENBALA as a part of an evolving utility and electricity industry?

Ron: I think New Brunswick is very much thinking in this integrated offering kind of way. I think there’s a feeling, and I think this is generally true, as we think about what ADS has seen. The notion of the customer not receiving a plethora of inserts and options from the utility, but rather an integrated offering that says, “Here’s the EE opportunities; here’s, maybe, pricing opportunities.” Those don’t, in particular, exist in New Brunswick, but if you think bigger picture. “Here’s demand management opportunities.”

The notion of presenting those in an integrated way to the customer, and I think the utility leading that. The utility, I believe, has a unique position to be able to present those opportunities to the customer. Then actually save money by integrating them, or by implementing those things at the same time.

I talked about this notion of, if you’re going to do an energy and process audit, let’s make sure that we capture both EE and DR opportunities, and if we’re going to connect the customer for DR, let’s make sure we capture a range of capabilities and value streams rather than just one.

I think that’s a trend that we’re going to see, and it’s very much a trend that New Brunswick is looking at, is they see, wow! You really can connect customer load, and you really can have it act as a dispatchable energy resource. They’re doing it now with almost 20 megawatts of connected load, where they’re saying, “We can modulate this load every 15 minutes in response to the needs of the grid.” You do that at not too much higher scale. You actually have a really, really useful grid resource.

I think they’re thinking about customer engagement, not as, “Oh yeah, we have to do that as a step,” but as core to the whole concept of EE plus DR. That’s a message that I know New Brunswick is doing, but is one that we continue to bring to utilities, and it really is resonating for them. They’re saying, “That’s exactly how we have to think of our customers,” and it hits on many of the concerns they have. How do we have a deeper relationship with our customer? How do we demonstrate more value for our customer, and how do we do that in a cost-effective way?

If you’re integrating these programs all at the same time, you really hit on all those things. You provide a better customer experience, you provide a range of values for the load, and at the same time, you’re building a tool, really, that allows you to manage your grid better in a more cost-effective way than the traditional approach of big iron in the ground.

Dan: Ron, can you repeat- I know on an earlier slide, you had the total percentage goal for renewable in the province.

Ron: I think their long-term goal is 40 percent from renewable sources. They’ve got a pretty substantial goal. That’ll be a range of renewables that may include some hydro, which they do have some in New Brunswick, but it’s a pretty hefty goal. They’re going to have to have grid management tools to support that, or they’re going to be using fossil plants, and that’s clearly what they don’t want to do.

Dan: Let’s close by talking about barriers that will either prevent this future vision of the electricity and utility industry, or barriers to companies like ENBALA being a part of it, in helping make that transition.

Ron: I usually talk about this as, there’s four major barriers to get over. The first one is customer engagement. The idea of connecting to a customer load in real time and modulating it in response to the needs of the grid can sound pretty scary to a customer. It’s sort of perverse, because in reality, the form of connectivity we supply is actually non-invasive. It actually doesn’t impact the customer, but you can appreciate that it doesn’t feel that way when you first hear about it.

Helping the customer understand that being connected in this way is not going to be invasive is something that needs to be explained. I believe it something like DR, which people become used to, and they’ll be able to refer to others who’ve done it before them, and I’m pretty sure we’re going to be through that barrier simply with time and effort and success.

The next barrier is what I call the silos barrier. When we think about innovating in this way, we think about customer engagement, EE, DR, multiple applications of DR, perhaps participating in organized markets using a DR resource to help manage generation better, maybe to help provide demand response in a way that could mitigate local grid problems. When we do that, we’re thinking about crossing the traditional utility silos that are the customer-facing, the transmission, the distribution, and the generation.

I’m a big believer, though, that the technology is going to give us the ability to go across silos. The utility needs to find a way to make that happen. Traditionally, the generation group never would talk to the customer group. They treat customers as things that happen to their generation that they have to deal with. I think to the extent that utilities can encourage cooperation across the silos that will encourage these business models to really flourish, because we really do want to capture value from across all these silos.

You’ve got the traditional risk aversion in the utilities, “This is new, it’s different.” I really do sympathize with utilities; they’re in a tough position. They’re being asked to innovate without ever letting anything bad happen and without spending any more money. That’s a tough set of things to pursue, so I think that leads to the fourth barrier, which is regulation. We need to make sure that the regulators give the utilities the ability to- cost-effectively, but give them the permission, really, to try some of these things that have such a great upside.

I think those are the four barriers that people have to figure out: customer engagement, silos, risk aversion and how to get around it in the utility, and then finding a way to create a regulatory construct that really works for everybody.

Dan: I think we’ll end it there, Ron. Thank you very much for being with us today. On the screen is information on how to get in touch with us here at ADS, but also directly with Ron. Thanks again, Ron, for joining us, and on behalf of Ron and myself, thanks to you for listening.