Vermont Business Magazine New Vermont Electric Power Company CEO Tom Dunn sat down with VBM to talk about the next era of electric transmission in Vermont. VELCO has completed most of its major upgrade projects and remains ahead-of-the-curve for most of the states in New England. Vermont is also a beneficiary of its location as an electric corridor, which could become greater with several gigawatts of new transmission lines proposed to route through Vermont from both Quebec and upstate New York. While Dunn sees this as a potential windfall for Vermont, there is much work to do to convince him of how those projects would be structured and how they would benefit VELCO and the transmission system in Vermont. A company called TDI has already started the permit process to bring a 1,000 megawatt DC line from Quebec and run it under Lake Champlain before turning east and terminating in Ludlow.
Dunn, meanwhile talked up local solar generation, but doubted that major new wind farms would go up in Vermont.
Solar works well for two reasons, he said. First, the sun shines and the solar panels work during the heaviest electric loads during air conditioning season in the summer. It’s not a perfect fit, he said, but it’s pretty good. Solar also tends to be very local and thus takes pressure off the transmission (VELCO) and distribution (local utilities) systems.
By contrast, wind turbines are built in remote places with tremendous loads that require sophisticated and very expensive transmission lines. He said he’s doubtful a developer would want to take on that expense to build a new wind farm, say, in the Northeast Kingdom.
As far as VELCO's near future is concerned, it is maintaining and investing in existing infrastructure to ensure the reliable service Vermonters have come to expect. During this interview, the word reliability was used frequently, which underscores the essence of VELCO’s mission.
VELCO owns and operates the state’s electric transmission system, the high-tension lines that crisscross the state. VELCO currently manages a system that includes 738 miles of transmission lines, 13,000 acres of rights-of-way, and 55 substations, switching stations and terminal facilities
Dunn: I came to VELCO after being head of engineering for eight years at the Department of Public Service in the early '90s and subsequently worked with NEPOOL down in Massachusetts. I was project management for the Northwest Reliability Project, which was the first big VELCO transmission project in 20 years.
That was very interesting. We learned a great deal during the course of that project. The lessons that we learned helped us get better as an organization for future projects: Cost-estimating, public outreach, those sorts of things. So that was a project that built a transmission line up from New Haven through Ferrisburgh, Shelburne and Charlotte. And it was very controversial and very hard and it was a very important project to get done from an electric grid reliability perspective. And things that we learned and subsequently applied to future projects made a real difference. The NRP had 40-something days of hearings before the Public Service Board. It was hard on the regulators, hard on the towns that were involved. So the next big project we did a couple years later, the Southern loop, had a day and a half of hearings. We got better at a lot of things, but the biggest thing we got better at was interacting with the public and sharing information and explaining what we were doing. We were very thoughtful in trying to get public input and buy-in before we went to regulators. That made a huge difference. Way more efficient and actually allowed us to bring the project in 10-15 percent under budget. On a $200 million project, that's a big savings. We did that stuff.
Over time I gained more responsibility and eventually became responsible for all the capital programs. And VELCO has been building quite a bit of transmission over the last eight or nine years, exceeding a billion dollars. So I did that program and then about three years ago I became chief operating officer. Earlier this year Chris Dutton retired and, after an extensive search and interview process, I was selected as the next president and CEO.
VBM: That must have been very exciting.
Dunn: Well, you know, it's funny, I hadn't gone through a competitive job search in 20-something years. And they had expressions of interest from about 200 people. They had an executive recruiter. They looked seriously at about 25 different people and that got down to nine or so, then there were three and then there were two. And an interview at each stage. It was a good opportunity for me to craft what I was thinking about for VELCO; where I saw VELCO going, so from that perspective it was helpful. And for the Board it was also helpful because they made this decision after doing a national search. And the fact that the guy in-house got it was great. It was important to me that I was the first VELCO employee to get the job. All the previous CEOs had come from the outside. (Chris Dutton previously was CEO of Green Mountain Power).
VBM: The last time I talked to Chris Dutton him I asked him if he was going to stay retired. And he said something like he promised his wife he would.
Dunn: I think he has a lot of other things he's doing that will keep him busy and he sits on a few boards. He's a terrific guy.
VBM: Does VELCO have any major projects on the horizon?
Dunn: We have over the next five years about $400 million worth of projects. Probably the biggest focus right now is on dealing with aging infrastructure. Some of the transmission lines, some of the substations were constructed in the late '50s and '60s. So we're at a stage where we're doing some replacement work on those. A lot of that $400 million will be in replacing structures and updating substations. Another part of the work is a project between Ludlow and Ascutney where we're going to be upgrading a transmission line. We hope to be in there in the next couple of years and that will be a rebuild of an existing transmission line. Those types of reliability projects will be the majority of what we'll be doing.
VBM: Explain how you get your funding.
Dunn: The cost of the transmission system in New England is shared among all ratepayers in the region. Each transmission entity, in the case of Vermont we serve the entire state, we pay the percentage of the overall load that we have. Vermont is about 4 percent of the New England load so we pay about 4 percent of the cost of the transmission system. In Vermont we pay a very small percentage of the cost of a project, but we also pay a portion of the cost of projects in the five other New England states. It's a funding system that's been very effective in getting transmission built to deal with reliability problems and I think that's helped the region in terms of congestion on the transmission system. That is a cost that consumers would pay.
When you identify a deficiency in the transmission system it's important to ask, aside from building transmission, are there other things you can do? They're called non-transmissional alternatives and it's something we spend a great deal of time in the planning work. So, say there’s a problem in the grid, can it be solved by energy efficiency, can it be solved by putting in small scale generation and things like that. We've been doing this now for several years and over the last couple of years we've deferred over $150 million worth of transmission.
We want to bring that discipline of asking, is there a better alternative, is there a cheaper alternative? to the rest of New England. In part, it's the right thing to do. Basically, it's the right thing to do; is it the least-cost way to solve a problem? While we've been successful in building projects and improving the reliability of the grid, there's a concern that transmission is becoming too expensive. We need to make sure we build only what we need to build.
VBM: Do the payments we send down there and they send up here pretty much a wash out over time?
Dunn: It really depends on how much construction a state is doing. Our program really started earlier than a lot of other companies’ programs in the region. Think of it as a mortgage payment. We pay about 4 percent of the mortgage payment for our transmission system, we receive back from the rest of New England about 7 percent of the revenue because of the amount of construction that we've done. Over time as our program slows down and other states catch up, our percentage of the revenue will probably get closer to the 4 percent that we pay. But for the next few years we'll probably receive more money than we pay. And it's important that the investments that the distribution companies (the electric companies: GMP, WEC, VEC, etc) that own VELCO, along with VLITE, earn a return on their investments. So the monies that are generated from the investments in the transmission system actually go to reduce the revenue requirements for the distribution utilities, so they can effectively lower the rates from what they otherwise would have been.
(The creation of the Vermont Low Income Trust for Electricity (VLITE) was due to the proposed purchase of CVPS by GazMétro and the merger of CVPS and GMP into one company in 2012. As part of this transaction a Memorandum of Understanding was included, which defined the inclusion of VLITE as a component of the merger approval. A significant ownership interest in VELCO was transferred by CVPS to VLITE, a public benefit, nonprofit corporation.).
VBM: It sounds like you’re in more of a maintenance phase. Rather than having to get something done or you'll have an imminent grid issue.
Dunn: I think the structured program is not unlike anyone who owns large assets like a transportation system or buildings, over time you need to start investing in those buildings and doing replacements and doing upgrades. We have about 7,000 structures in our system and until about three years ago we were replacing about 25 structures a year. And if you do the math, that's well over a hundred years. These are wood poles. They simply won't last that long. So we looked at the situation and we came up with a five-year, and it may be a little bit longer, program to kind of get to a place where we know the condition of our system, but we're not having to do it in any kind of emergency basis. We're picking segments of the system to work on, so we're picking ones that are in most need of replacement first. So it's not an emergency.
In what's driving this stuff, a little bit of background might be helpful.
You remember the 2003 blackout that affected a large part of the country. When people looked at what caused that blackout, a lot of it was that the reliability standards that utilities follow were not mandatory. They were a sort of voluntary agreement among utilities. In some cases it was found that utilities were not doing a good job in terms of tree trimming. Or in some cases, the computer systems weren't running properly. Congress looked at that information coming out of the blackout and passed legislation, administered by the Federal Energy Regulatory Commission, that made those standards mandatory. They put some pretty severe financial penalties in place on transmission owners who didn't meet those standards. And it makes sense because the transmission system from here to the Rocky Mountains is one, interconnected system.
If VELCO didn't do its job in terms of trimming trees, or maintaining its computer system or didn't do its transmission planning, we could become the weak-link. If we don't do a good job, and there is a problem, that problem doesn't stay in Vermont. So we're trying to stay ahead of those reliability issues.
For instance, there was a problem down with Florida Power & Light. A technician went into a substation and disabled some protective systems to do his work. It wasn't nefarious or anything, he was just doing his job and he had the misfortune of a fault occurring inside the substation and the fault took out most of Florida. So when the investigation was done and the regulators looked at what had happened, they fined Florida Power & Light over $20 million.
So those are the kind of things that can happen. We get audited regularly on transmission planning, cyber-security, how we run our operating center, things like that. Compliance is a big part of our business. That was something, quite frankly, that was not even on the radar screen in terms of dedicated staff to support compliance to the necessary standards.
VBM: Vermont largely if not entirely escaped that 2003 blackout.
Dunn: That's right.
VBM: In retrospect, is there understanding of why Vermont escaped?
Dunn: I think we were fortunate. The center of the blackout was Cleveland and you had a situation where you had a bunch of power plants and transmission lines that were tripped off line and you had power coming in from different regions. There were literally thousands and thousands of megawatts, and Vermont is about 1,000 megawatts, and, I don't know, 10,000 or 15,000 megawatts were swirling around the Midwest and the system became unstable. And you run the system to try and make instantaneous balance between the amount of electricity being used and the amount of electricity being generated. And so all of a sudden you have a situation in which you lose power plants and you still have lots of demand. Power starts coming in from unexpected locations.
Now, you have the ability to model that type of situation using commercially available software and that's part of running the grid. But in the case of 2003, that computer capability was off-line and the folks in the operation center didn't know it. They looked at a screen and it was static. They didn't know how vulnerable they were. In terms of 2003, we were fortunate. Not that we were doing anything that made us any more vulnerable. But it was more the location of where the outage triggered was geographically remote.
Now the blackout in '65 affected much of the Northeast and that started on the St Lawrence Seaway.
VBM: I remember it very well.
Dunn: I was around, but I don't remember it.
VBM: Vermont is about 1,000 and New England is 26-28,000 (megawatts), to put it in perspective.
Dunn: We're about 1,100 and our all-time peak occurred in the summer of 2006. What is interesting to me, and for me it shows a fundamental change in our business, is that this past July we had really hot weather and we were in an ideal situation to see a new system peak. It was hotter, it was more humid, the heat was building from the beginning of the weekend and then up through Wednesday and Thursday and despite of those conditions, our peak demand in 2013 was 6 percent lower than it was in 2006.
For someone like me who had been in the industry for 20-something years, that was a fundamental shift in what I would have expected to see. Historically, the industry has seen a 1 to 1 1/2 percent increase in demand every year and given the system conditions I would have expected to see a new system peak. And we didn't see that. I mentioned earlier about deferring transmission. And part of that is we're starting to see the effects of, particularly, the efficiency investments, but also the solar that’s being installed in the system and other distributed resources. VELCO serves the net peak, which is the total demand minus all of those resources. It affirmed our decision to defer some of our transmission. We think something is changing in our business. We think energy efficiency is the primary driver of that. But then all of the things that are coming on top of that, like the distributed solar you see all over the state. That's really changing the business.
VBM: Solar has been pretty well received. How is it helping the grid?
Dunn: In central Vermont there was an issue between Ludlow and Rutland and we were looking at how to upgrade that transmission line. The starting point in transmission planning is the load forecast. So what is the demand that the system has to meet? We make sure that we can supply the peak demand in a resilient fashion so that you make sure as you take elements out of the system, you're still able to meet peak demand. So what these resources effectively do is lower peak demand, so whether it's energy efficiency or whether it's solar, it has the effect of dampening that demand.
Solar in particular is pretty good because often times the peak demand is in the afternoon, so it lines up pretty well, not perfect because we also see at 6 or 7 o'clock when people start to come home, particularly now that it's summer time in Vermont, and they turn the air conditioning up, and we see an increase in demand for electricity. But it does have a pretty good correlation between demand and helping offset it.
As far as transmission planning, solar is a small fraction of a percent; it's not a big deal, but what happens when it's 5 percent or 10 percent of your peak demand? For grid operators, how do you handle that? One of the things we're working on is that we have a partnership with IBM and Green Mountain Power, and others, to look at taking a sophisticated weather forecasting program that IBM has from its Watson labs and helping us do a better job of forecasting how much demand for electricity there's going to be and also how much production we're going to get from the solar panels that are distributed all around the state. Right now we have no vision as to what they're going to produce. So if it's a fraction of a percentage it doesn't matter so much, but if it gets to 5 or 10 percent of peak demand, and it’s on par with local hydro electric generation, then that will become important to know.
Of course, there's been quite a bit of wind projects that have been built around the state. And that probably presents more of a challenge in some ways because typically the locations where the wind is really good there is not a lot of electric demand. The grid that was built in the '50s and '60s was built to serve that electric demand and not to export power out. So the challenge from the grid perspective is maintaining reliability, that's job one, and then how do you make sure that wind power can get out. It's something that's new for VELCO over the last three or four years. I think we're at a place right now that it's working pretty well. Early on and with some of the new projects there were times when in order to maintain reliability, some of that generation was curtailed. But we're not seeing that now. There was equipment that was installed that helped maintain reliability, while allowing that generation to get out to the customers.
VBM: You're talking about last summer when ISO New England curtailed some of the power coming from Lowell and the governor was quite upset about that. Was that just ISO being very conservative about ensuring the reliability of the system?
Dunn: The equipment upgrade occurred after that. ISO's job is, number one, to maintain the reliability of the grid. They have a set of rules that they follow. People view that they're too conservative in some cases; my view is that those are the rules that are put in place to run the grid and I think the reliability of the grid in New England has been very good.
But there are opportunities to be more effective in terms of information coming back from the grid. Sometimes there are conservative measures put in place to preserve reliability that are in part conservative because not all the information that might be available is getting back. I think over time what we'll see is a grid that has more information coming back to the system operators so that they can run the system more effectively. And that will help. In terms of northern Vermont, there was a synchronous condenser put in at the Jay substation that helped that situation significantly to the point that today that issue of curtailing is not really an issue.
VBM: ISO is kind of the boss of the system. Everyone has to follow their direction.
Dunn: That's correct. So we as a transmission owner work with ISO. ISO is in charge of planning they're in charge of system operations. If someone wants to connect a generator larger than 5 megawatts, they have to go through the ISO. And basically they must demonstrate that the generator is not going to affect reliability. So they are the boss. They're the ones that tell us, for instance, that there's an interface in Northern Vermont and we need to work with ISO to ensure that we don't exceed a certain amount of power. In terms of running the grid we are a local control center under the direction of ISO New England.
VBM: It seems that one problem holding up the development of new wind generation in Northern Vermont is the cost of running a transmission line up there. (Eolian Renewable Energy, a wind developer based in Portsmouth, NH, in May withdrew its application to connect power from the proposed, 20-turbine Seneca Mountain Wind project in Ferdinand to the region’s electric grid. The likely reason was the cost of the transmission upgrade to the developer.)
Dunn: I think we're in a state of equilibrium now, where the amount of wind works for the system that we have. For the next project that shows up, their basic interconnection costs are going to be pretty expensive, I believe. But perhaps more importantly, if they decided to pay for those interconnection costs, and we're talking we're talking tens of millions of dollars, you're in a situation in which you have two or three significant plants and there's only so much capacity space to get out and so they're kind of competing against each other. That doesn't strike me as something that makes sense. If we as a state want to have more wind, we need to figure out a way to make sure that wind can be delivered. Instead of having a situation in which three or four plants with, say, 150 megawatts of capability can only deliver 120 megawatts or 110 depending on system conditions. That doesn't sound like a good result to me.
VBM: And solar doesn't have the same kind of issues that wind has?
Dunn: No. It's probably more of a challenge for the distribution utilities and for the distribution circuits. Those were almost entirely designed with the thought that the power comes from the local substation to the local distribution system to the streets out here. And now you're in a world where, depending on the location, there's a great deal of solar on the distribution circuits, and that affects the flows.
There are places where, and I'm not sure it's true in Vermont yet, but there are places around the country where power flows back to the substation and that's a real challenge for the distribution utilities to work through. It's not insurmountable. It's just a change in the grid in terms of how it has traditionally operated. That's the nature of where the grid is going. Where it accommodates the choices that consumers want. It has to be more flexible, it has to be more resilient, the ability to move data around. We're doing that in the transmission system and I believe it's also happening at the distribution system level. That's where the future is going. People want it and state policy supports it and it just makes sense to make sure the system can handle it.
ISO New England looks at what the demand is going to be and they make estimates and they determine what generating plants are going to run. They look at how much wind is generated, how much run-of-river hydro and that determines how much fossil that has to run as a result of how much demand is left over. So getting that forecasting correct is important. They have a lot of experience with hydro, they're getting better at wind. On a day with low demand, you'd probably find that fossil plants aren't running that much. In New England and other places there are baseload plants, like nuclear, that they like to run continuously. In places like New York where there's a higher percent of renewables, some of those nuclear plants may be affected in terms of how they operate.
VBM: It's probably easier to turn the burner down on a natural gas plant than a nuclear plant?
Dunn: Yes, it is.
VBM: The local utilities don't like to turn on local generators to fill gaps in generation, which is what happened when ISO turned down the output of the wind plants here. Is there much of that?
Dunn: There's a number of those plants around the state and they run occasionally, typically during very cold periods or during really hot times. This past winter was an interesting time in New England. The New England generating mix is about 50 percent gas. And this winter, with the extended cold, record-breaking cold in New England, there was a great deal of natural gas being used for heating homes and not as much gas available for the gas power plants.
So this winter a significant percentage of the peak demand was met by oil and coal in New England, much more so than if you looked at the installed mix. And it was because the natural gas pipeline capacity coming into the region was inadequate to supply both the heating demand and the gas-fired generation demand. There was tremendous price volatility as well. ISO New England said that in the months of December, January and February, New England spent more for energy in those three months than they did in all 2012. Gas became scarce and it translates directly into the price of electricity on the spot market.
VBM: And we know the Vermont Yankee nuclear plant, in its last year of operation and acting as a merchant plant with the ability to bid on the spot market, made over $100 million in the first quarter of the year because of the high prices and high demand. Speaking of Vermont Yankee, we know it's going off-line by the end of this year, what impact will it have on the reliability of the grid and VELCO's business?
Dunn: We work very closely with the ISO on looking at the transmission system. At this point we've done some upgrades in the Vernon area in the last four or five years. At his point it doesn't look like it's going to be a significant impact on the VELCO system with Vermont Yankee going off-line.
VBM: There's been a lot of discussion lately about Vermont being an electric corridor for New England, with power coming from Canada or New York, with high-capacity DC lines running into or through the state. What is VELCO's view of that?
Dunn: There are a number of projects that are being contemplated. A little bit of background. The governors in the region reached an agreement in December to support bringing in additional renewable supply. In particular, the southern New England states have renewable energy goals that they're going to have a hard time meeting because they simply cannot build enough renewables in those areas. So looking at how the region can collectively work together to bring in additional renewable supply was one of the main drivers. There was also concern about the gas pipeline capacity. There's also a lot of concern about the number of power plants in the region that are retiring, not just Vermont Yankee. So in addition to looking at Quebec or Northeast New York for renewable purposes, those power lines could also help bring in future supply to just get more power into New England. So that's part of the framework.
The project you were talking about, TDI, is proposing a 1,000 megawatt line. It's basically a transmission line from the Hydro-Quebec system delivered to the VELCO system. They have a request in front of the ISO to study that proposal. The governors' initiative and the work New England's regulators have done to advance that has generated additional interest in building transmission in Vermont. And the reason for that basically is that we're the shortest path from Quebec to the New England marketplace.
So we also have a project that's been proposed from Plattsburgh (New York) to the Essex area. Also, Northeast Utilities has proposed two projects, as has Hydro-Quebec itself. In total, there are several projects that are driven by bringing in renewable supply and, seeing the opportunity that New England presents with 4,000 or so megawatts retiring, to help advance renewable goals.
Hopefully, if it's done right, and we get contracts, it will help mollify the cost volatility that we're seeing right now. So we're looking at these projects.
The thing about it is that these are going to be expensive projects. TDI is proposing to go with a merchant-based line (selling to the open market instead of being locked into contracts). They're not going to seek to share the costs with New England's transmission customers. Their view is that the customers of that power will pay for that line. Others are anticipating a new cost allocation method similar to the way reliability projects are being paid for and shared with the rest of New England. That is something the region's regulators are working on.
So our team is doing their homework to determine what projects, what locations, will work best with the grid. In some places if you put a 500-megawatt injection into the VELCO system it could create a real problem in terms of overloading the adjacent lines. Where in other places, it might fit OK. So we're looking at that. We've talked to every one of these developers. We’re looking at these opportunities to see if we have an interest in getting involved. Right now we don't have any interconnection requests.
The concern that I have is that if we sit on the sideline and the costs are shared, we'll simply be paying for these transmission projects that are being proposed to be built in Vermont. And I happen to think that if transmission is built in Vermont, that VELCO should do it. Or have a significant role in doing that. Obviously we know the landscape and I think we have a successful track record of building transmission here. That's why they've talked to us. That's why they're interested in partnering with us. We are working hard as a company to understand what makes sense in this landscape.
For TDI, it’s reasonable to assume that the permitting would take a year and the construction would take a couple of years, so under the best-case scenario it could be 2017 to get the TDI project built. That would be really, really fast. No one's put a transmission line in the lake. We have a transmission line that runs from Plattsburgh to Grand Isle and that's only about a mile. With TDI we're talking about something that's going to be 10 miles or more (in fact it turned out their application calls for about a 100-mile marine cable). So I don't know what kind of issues they're going to run into in terms of getting regulatory approval for that.
(Shortly after this interview with Tom Dunn, TDI submitted in late May, as expected, a permit application for its line that would run from the Quebec-Vermont border, under Lake Champlain and then across the state to Ludlow. See related story. Responding to VBM from VELCO was Vice President Kerrick Johnson: "They want us to enter into a partnership with them... immediately if not sooner (As does every single other project developer.) We're not yet convinced that the deal TDI is offering is VELCO's best option to secure maximum value for VT. There may be other, significantly better financial arrangements, approaches and partners.)
VBM: What is the upside for Vermont for being this electric corridor?
Dunn: Well, Vermont will have to approve any proposed project. So they'll have a say in terms of what will it look like. The likelihood is that these projects will be underground. They'll be an opportunity for perhaps a Vermont benefits type of fund. I've heard talk that there might be money available, for example, to help clean up the lake. If VELCO is involved as a partner, there's an opportunity to earn a return and, like our reliability investments, that return would go back to consumers to lower rates. These lines present the opportunity to perhaps, as the distribution companies need the power, to enter into contracts to buy some of that power. Those are some of the benefits I see for the state. But there's a good deal of uncertainty. The allocation mechanism isn't set yet. Like I said, for us it's a different model and I want to be careful that we don't put ourselves in a position that it presents an unacceptable risk.
VBM: With all the generation that is going off-line soon in New England, are we then looking at higher electric rates? (ISO reports that at least for this summer, there should be plenty of supply)
Dunn: That's a difficult question to answer. It depends on what you replace it with. The reason those plants are retiring is that they're not economic. One of the things that natural gas has introduced is that it's a very efficient way to generate electricity. Provided you have adequate supply, provided you can ensure yourselves that during peak periods you don't see some tremendous volatility in the price. As I see it, natural gas is likely to be an economically viable replacement for a lot of that. The question then becomes, in terms of meeting the renewable part of the portfolio, how do you do that? What is the most economic way to do that? What I've seen in Vermont is that the wind projects the utilities have invested in, they appear to have been very economical. What's not clear, for example, is what the economics would be for a large block of renewable power that New England wants to buy.
Clearly, if that gets into the power supply mix and it's more expensive than what it's replacing, then that's going to raise rates. But I don't know the answer to that question right now. There are a lot of challenges. The large deployment of distributed solar presents interesting challenges for utilities. The industry is changing in a lot of different ways and I know that the utilities are wondering what to do and how to respond to that.
VBM: Is there a technical limit to how much electricity Vermont can buy from Hydro-Quebec? It seems they have an unlimited supply.
Dunn: Their supply actually isn't unlimited. In terms of transmission there is a limit in the number of interconnections. Vermont has one through Highgate and another that runs through the Northeast part of the state down to southern Massachusetts. I don't think there's an enormous amount of additional space. Hydro-Quebec, I think, is very interested in selling additional power to New England and they do have additional supply available. There's a question in my mind that if Massachusetts and Connecticut want an enormous amount of renewables, will that exceed the available power up in Hydro-Quebec? But in order to bring in additional power from Quebec, you're going to have to build additional infrastructure. There are projects proposed in New Hampshire as well as the five or six proposed here in Vermont. So my expectations would be that additional supplies would require additional transmission lines.
VBM: Anything else?
Dunn: This isn't the same industry it was 20 years ago. The technology is changing. Today in Vermont we have 1,500/1,600 miles of fiber, almost to every substation in the state. It also builds upon the SmartGrid grant that VELCO administered and that the distribution utilities used with the $69 million grant to install Smart meters to over 90 percent of customers in Vermont. So the technology is changing and I think of it as a platform for innovation.
So all of that makes it a lot of fun to be in this business.
Tom Dunn was named CEO of the Vermont Electric Power Company, commonly known as VELCO, in December 2013 and formally took over from the retiring Chris Dutton in February. Dunn had been COO since August 2012, having served previously as Vice President of Transmission Services since 2010 and Director of Capital Projects since 2005. Prior to his arrival at VELCO in 2000, to serve as the company’s Manager of NEPOOL Relations and Project Manager, Dunn served as the Vermont Department of Public Service’s Chief of Utilities Engineering, beginning in 1992. He earned his MBA from Boston College and a BS in Marine Engineering from Massachusetts Maritime Academy. Tom and his wife Kirsten and four daughters live in Montpelier. Immediately after this interview with Vermont Business Magazine's Tim McQuiston in mid-May in South Burlington, Dunn hustled back to catch his daughter’s high school tennis match.