How BPA Views Flexible Demand-Side Resources for the Northwest
Elliot Mainzer, Administrator and CEO of Bonneville Power Administration, kicked off day one of the Northwest DR & Energy Storage Summit in Portland, September 27 and 28, 2017. He gave us a high-level look at how BPA, a central player in our regional energy grid landscape, is looking at the roles of DR and energy storage. Smart Grid Northwest has captured some of his keynote speech below—as well as remarks in a subsequent interview—focusing on three areas: commercialization of DR, impacts of this summer’s south-of-Allston transmission-line decision, and the role of hydro in the energy storage “stack”.
Smart Grid Northwest: In his opening remarks, Mainzer recapped DR initiatives at BPA:
Over the last several years, we’ve tested demand response and even energy storage with just about every application we could find… We’ve looked at dispatchability. We’ve looked at contractual structures. We’ve looked at how to integrate demand side resources into our power and transmission system operations. We’ve looked at steel mills, cold storage facilities and hot water heaters.
Just a couple of years ago, as the hydro system started to hit the physical margin, we started actually running auctions on a fairly regular basis for balancing reserves for wind integration. We started saying, “You know what? This is starting to look commercially viable.” I said to our demand response team, “Guys, my principle guidance right now is I want to start moving us out of the R&D space and into the commercialization space. I want us to start looking for specific opportunities to leverage demand response and storage resources to meet the energy, capacity, and flexibility needs…”
Another thing that we’re going to be definitely looking at is working with Portland General Electric, working with Clark Public Utilities, for south of Allston congestion relief, and working with other utilities in the south of Allston region. We’ve been aggregating additional demand response capability for super peak summers. We’re looking at flow control devices. We haven’t seen a lot of it deployed yet for 500 kv lines, but they work well for 230 kv lines, and we are hoping [to] scale it up to allow it to redeploy flows away from that congested element of the system towards less congested paths.
A member of the audience asked about if residential DR would be part of the plan.
The basic answer is yes, and I would say that we’ve spent a lot of time working on contractual mechanisms and visibility mechanisms [to make it] dispatchable… A 3 kW solution isn’t going to help us, but aggregated to sufficient scale with a point of delivery that can actually be dispatched, with on-demand call rights and a contractual understanding of both capacity price and energy dispatch price, with a specific load factor, with parameters along the lines of what I’ve seen other aggregators provide in other parts of the world could be useful.
And that scale would be…?
I don’t think I’ve ever heard us talk about a minimum size, but … close to the tens of megawatt scale.
Mainzer talked about this summer’s decision not to build the “south of Allston” transmission line along the I-5 corridor, opting instead to pursue non-wires alternatives.
By the time we had racked up the total costs on that build, it was north of a billion dollars for 79 miles of 500 kv transmission, not to mention the political capital and the complexities of getting that line built and putting so much capital in one basket. We sent planners back to the drawing board and they did an unbelievable job re-imagining the question.
The question wasn’t just, “Okay, what transmission line do we need to build?” The question was really, “How do we manage congestion on this path.” They came back to me with a much more flexible and scalable non-wires approach to managing that path which would involve everything from re-dispatching generators along the path, demand response, importing more power out of California using the EIM market to help with a congestion management, potentially the use of flow control devices, battery storage, and a whole suite of applications that we believe can be deployed in this commercial context.
I made a fairly fateful decision not to build that line. Not to defer it, but to not build it. We committed to other solutions, both non-wires and supporting other projects that would provide flow relief across the South of Allston path. That doesn’t mean that’s the end of transmission construction on our system, or even on the west side, but in terms of developing a more flexible and scalable non-wires approach… it’s given us a deeper solution set. We’re very excited about that…
We asked Mainzer how the decision is already playing out around the Northwest.
We’ve already started to see change around scheduling behavior and import behavior and folks paying more attention to the probabilities of curtailments and things like that. One of the things that’s really fascinating is there’s just the power of the decision itself in terms of impacting behavior of market participants. By changing the way that we subscribe the transmission system through short-term transmission products, that’s also having a positive impact on loading the path.
One of the really fascinating things we’ll watch in the months and years ahead is to see how does utilization of the path evolve relative to the total transfer capacity across that part of the system, and what will be the additional need for redispatch and other load management services? How quickly will that evolve? How fast will it happen? How will other changes in flows occur as the EIM advances impact the utilization of the path?
As we define those needs, and as we figure out how much capability we need to continue to be able to sell capacity across that path, we’ll start rolling out commercial subscription processes, RFOs, things like that, to buy what we need… When you actually go out and use demand response, that’s an awakening. It’s one thing to sell it, it’s another thing to have it called upon. That’s been a perennial issue in demand response for years and years. We used it. It’ll be interesting to see whether folks come back and say, “Hey, I really liked that. It was worth it,” or whether we have to go to another stack of resources.
Day two of the Summit explored energy storage issues and opportunities. Some renewable energy providers are starting to look at how to use energy storage to balance renewable energy sources. We asked Mainzer about how those commercial efforts impact BPA’s planning or outlook?
We would like to be part of that storage stack… The guys that are going after 100% renewables need high load factor flat service, they’re going to be looking for shaping. We think that for some extended period of time, not forever, [hydro] will be able to provide that shaping and that capacity at much, much lower costs, without carbon emissions and quite frankly without some of the rare earth and disposal problems… We’re also very conscious of our own competitive posture, and we’re going to be chasing that business…
You go out to Sherman County and you look at the sea of wind turbines out there… That resource would not have been made available without the Federal Columbia River Power System. It’s impossible. You didn’t have the gas technology at the time. You didn’t have the transmission. You didn’t have the flexibility, especially for such a highly concentrated wind fleet with minimal diversity. The way we see it… We’re grateful that we were able to help deploy the flexibility and the zero carbon capability to help get that resource to scale…
The wind and solar are over that price curve that was killing them for years and years… As we go to much greater scales, we are going to be rooting for the other technologies, because we think they have applications, but we also think there’s a core role for hydro as part of the base load flexibility stack. We want to be part of that portfolio. … We want to go into the higher-end clean capacity market and be partners with all the service providers.