Pacific Northwest electricity going carbon-free without natural gas?

Rating: High school and post-secondary

Summary: Markham interviews Ben Kujala, director of power planning for the Northwest Power and Conservation Council based in Portland, Oregon. They discussed the extent to which natural gas should be relied upon as a “bridge fuel” as the Pacific NW considers the right mix of wind, solar, storage, nuclear and hydropower to provide carbon-free energy at an affordable and reliable level.

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This interview has been lightly edited for clarity.

Markham Hislop: Welcome to another episode of Energi Talks, the podcast where we discuss global energy issues with experts from around the world. In this episode, I’ll be talking to Ben Kujala director of power planning for the Northwest power and conservation council based in Portland, Oregon, we’ll be discussing the extent to which natural gas should be relied upon as a bridge fuel as the Pacific Northwest considers the right mix of wind, solar, storage, nuclear, and hydropower to provide carbon-free energy at an affordable and reliable level.

To set the stage here, your organization, which is a federal agency, created under an act of Congress, is preparing its next five-year plan. That’ll come out next year. And your area that you’re dealing with is around the Columbia River. As I understand it, which has 31 hydroelectric dams that produce 22 gigawatts of power and meet 30% of the Pacific Northwest
Northwest electricity needs. Is that correct?

Ben Kujala: Mostly. So we are actually an interstate compact. The federal government did form us through a piece of legislation, but we’re a combined entity that is a cooperation between the States of Oregon, Washington, Idaho Montana. So we’re not exactly a federal agency, although we were enabled by federal legislation, one of those confusing little sort of intricate government things.

Markham Hislop: Your organization is preparing this regional plan. And I think this is a fascinating topic because, federal, national and subnational governments around the world are grappling with this issue. And part of it is that if you invest in a natural gas combined cycle today in an attempt to bring down GHG emissions, effectively you’ve committed to a 30 to 50-year investment because that asset isn’t going to be mothballed after 10 or 15 years, and that locks you into GHG emissions. Is that something that your organization is considering?

Ben Kujala: Absolutely. We are in the very initial stages of looking at results. I should say that everything that we’ve seen thus far is just very early on in our planning process. What we have definitely seen is, of course, you build a new plant and it has multiple impacts on the system.

It adds some capacity for those times where you really need energy and they can respond with dispatchable electricity to that capacity need. It also tends to displace older natural gas systems. If you do build a new plant, it doesn’t necessarily mean that you’re just adding emissions on top of all the existing emissions we have in the system because a brand new plant is way more efficient than an old plant. It tends to run when those old plants would have otherwise and in those cases, it’s reducing emissions. But there are some times where you need a lot of plants altogether and they’re all going to work in concert to meet capacity needs. And then in those times, you would have some increased emissions then maybe alternatives that you could have done instead of building a natural gas plant.

Markham Hislop:  Now, I would imagine that your organization was looking south to California this summer with the issues that came up with its blackouts and the conversation that followed about the role that renewable energy played in those blackouts. Did that influence your thinking at all?

Ben Kujala: Yeah, we and everyone else in the West were certainly looking to California. I would say that we have always been very kind of cautious about how much we rely on the exchange between the Northwest and California. When we look at resource adequacy and what we need to do to ensure that we have reliable power in the Northwest, we have some limits that we put on what we’re willing to take from California from out of our region.

I think that that just emphasized that practice is something that has always been something common in the Northwest. We tend to have more generation than node. We tend to be a long region where we produce more power than we use. But I think that’s clearly something that we’re very cautious about. And so certainly looking in there and looking at, of course, the characteristics of the generation that did put California in that spot, what was happening with imports and exports is something that everybody continues to kind of mull over.

The challenge of these things is, of course, there’s no right answer. There’s a lot of things that were going on with that situation: really high loads, extreme heat, imports and exports were pretty high during that time. A lot of it was kind of internal problems that they had. But there’s still stuff that we’re learning today and there’s the stuff that I think we’ll continue learning as we dissect that event.

Markham Hislop: Now I picked up on your comment about limiting the amount of power that your region imports. And I know that other Canadian provinces like BC, for instance, are comfortable in the 7% to 10% range of their total usage. Is that the kind of range we’re talking about for the Pacific Northwest?

Ben Kujala: We get together a bunch of experts in an advisory committee panel and we ask, what makes you sort of feel comfortable in terms of the ability to import and export? We’re still vetting that information for our current plan again.

Generally, we haven’t had a percentage. It’s been kind of at what times of the year are we more comfortable and to what level? It might be that during the off-peak hours, we’ve always felt like there’s more power available, so we’re willing to import power during the off-peak hours and back off the hydro system so that we can produce more energy in our hydro system during the peak hours.

We have different levels per season and kind of per hour load shape that we’re seeing. And that’s something that’s very dynamic with solar coming on in California, which is changing the hours that we think are going to be the ones where there’s a lot of available imports. So, we don’t have a percentage per se. We just have kind of an expert informed, ability to import that we build into our models for our analysis.

Markham Hislop: Well, let’s talk about California solar. A little shout out to our friends at Utility Dive (see Related Stories above) for an excellent article that they did on your planning process. In that article, it was mentioned that cheap California solar might be one of the things that the Pacific Northwest West relies upon. But, British Columbia is saying the very same thing. There’s only so much cheap California solar to be had and quite a bit less that can actually be transmitted out of California. All of these competing interests in the Western electricity market adds I would think another layer of complexity to your job?

Ben Kujala: I would say it kind of depends on how you see the future playing out in California. If you’ve heard of [consulting firm] E3, they’ve done a bunch of studies on the increased penetration of solar that say curtailing renewables is cheaper than having to build a lot of infrastructure like batteries to store the energy and then use it at a later time.

Now there might be other things driving you to build batteries. Certainly, California has some efforts going in that direction too, to try to build batteries for capacity. But I think most scenarios show that they’re going to build resources well ahead of the ability to store. So there’s probably going to be some renewable curtailment during different parts of the day.

If that’s the case, then as much as they cannot ship the power out, California will be perfectly happy with that result. Based on the policy that they’ve passed, it’s to their advantage to get as much power built as possible, whether California is the one using it or not. I do think you’re right. It comes down to the limits on the transmission system and the ability to export solar power out of the state. If you believe the sort of build projections that they’re putting together in the state agencies down there.

Markham Hislop: Not that long ago, I interviewed professor Lucas Davis who’s an economist at the Haas Energy Institute at Berkeley. He said that a lot of the solar that has to get curtailed is because of problems with transmission. That there are regional issues with transmission. And in California, building new transmission capacity is very difficult for environmental reasons and permitting reasons. And it takes a long time it’s very expensive. And so, you know, there was a very good chance that some of the solar will be trapped because of transmission issues.

You did mention batteries within the California context. Let’s talk about it in the Pacific Northwest context. What role do you expect batteries to play in your power system going forward?

Ben Kujala: That’s a really complicated problem in a system that has a lot of hydro, which has some ability to store power and then to produce that power at a different time. So how batteries compliment that is something that we continue to be working on. And I don’t think we’ve got a full picture of it yet. We’re still trying to refine our approach, how can batteries be complementary to the hydro system. That’s a pretty big and dynamic question, one that is not easy to answer.

So I would say that if you’re looking at a future where you’re not going to build natural gas it seems clear that batteries have some sort of role or some sort of storage has a role, whether it’s batteries or pumped storage or something else. But I still think that figuring out when, and to what extent you bring them into our system is going to be complicated. It’s something that we are working on. And I will tell you, I don’t have a simple answer for you on that one right now.

Markham Hislop: Fair enough. Batteries have really only seriously entered the power grid conversation in the last 12, 18 months, let’s say. A lot of that is driven by the really dramatic decreases in costs in lithium-ion and the dramatic costs that are being forecast between now and 2030. I think we’re talking about it just with battery packs, EV battery packs for $137 a kilowatt-hour today to maybe as low as $57 a kilowatt-hour by 2030. That’s a tremendous decrease and I would assume make batteries more attractive for organizations like yours.

I want to talk about an issue that I find fascinating, and that is how planners like yourself and your organization, take into account the electrification of the economy due to climate policy? That depends on extensive electrification. Again, using the British Columbia example, if the climate targets of the current government are met by 2050, it could mean a doubling and perhaps a tripling of power consumption in the province. That would be a tremendous amount of new generation.

I assume because we’re talking about the Western part of the US where the climate is a big issue, that similar kinds of policies are likely in place in the States that you serve.

Ben Kujala: There are some active conversations going on in the state of Washington. The governor’s got an agenda on electrification. I think the City of Seattle has some things going on as well. And I think there have been some other conversations in Oregon and some of the other states too. It’s definitely something that we are watching.

I will say our projection is considering switching from natural gas to electricity – for example, space heating like homes and commercial buildings, but also other commercial uses like commercial cooking – because it’s an immense electric load.

When you look at buildings and the way that they could add load onto the grid if you change over new construction [from gas to electricity], you’ve got stock turnover, it takes a little while. A you remove buildings and you add new ones, it adds an extra sort of increment to the electric load that could really build to be pretty amazing. If you start retrofitting buildings – taking out natural gas infrastructure and adding electric, that would be a whole nother level of electrical load on the grid.

So I think it is definitely something that could have a huge impact on electric load.

Climate is something that is going to be underlying most of our work. Since in the Northwest we worry about hydro a lot [because of water levels], it’s another thing that is impacted by climate change. We see that in the sort of initial studies that have been done in the Northwest about climate change. We see an increase in generation in the winter from the hydro system and then a decrease in the summer. And so that kind of changes the dynamics of what we’ve been traditionally used to seeing come from the generation on the hydro system.

You have to take that into account as well when you’re looking at if electrical heating increases the winter load [on the grid].

If you really start aggressively going after what is currently served by natural gas, it’s just going to go beyond our current generation fleet, no doubt.

Markham Hislop: While we’re on the subject of policy and regulation, the Utility Dive article made a very interesting point that Washington is a little more aggressive than Oregon and the other two states have an even more uncertain regulatory landscape. That makes financing of new natural gas-fired plants more difficult because you’re not certain that a plant designed to last 30 to 50 years will be around to recover its costs and be profitable. Has that come up in your considerations?

Ben Kujala: Absolutely. I will say we did our best to collect [information about regulations] not just in the Northwest, but throughout the entire West, looking at where it’s possible to build new natural gas plants. And it’s not just about regulation. I think a lot gets laid at the feet of regulators or state legislators, but there’s a lot of corporations out there with similar corporate policies. And we tried to do our best to understand that as well.

So in our region, for example, Idaho Power doesn’t have a regulation saying that it’s not going to build gas plants, but it is the main utility and it has a goal to be carbon-free by 2050. When you consider the aggregate of the regulations and the corporate goals, it does seem like it’s going to be really hard for people to build new natural gas plants in the entire West.

There’s just a few places that you could anticipate maybe seeing a couple in northwestern Montana. One of our states as well does have a in its IRP [integrated resource plan]. I think some, some plans for building gas. There seems to be some potential in Wyoming or maybe Utah, but it’s pretty limited across the West.

Markham Hislop: Let’s talk about offsets because I understand the Washington Clean Energy Transformation Act requires that all electricity sold in that state be greenhouse gas neutral by 2030, but it allows emissions or credits. What role will offsets play in your plan going forward?

Ben Kujala: I think it’s a pretty narrow set of things you can use for those offsets. It’s not just go online and find a carbon offset, sort of what you can buy if you’re a business traveller your plane’s greenhouse gas emissions. So in, in that case, one of the main things you can use is the rec’s that are created by the RPS generation. So I think it creates an extra sort of, pressure on the rec market to have more RPS qualified generation that basically can use to retire those racks so that you can continue having that kind of carbon-neutral emissions. And that’s probably going to be the most common, I think, element that they would go after. So the end result is of course you have more renewable generation being added into the system because you want more of those recs to be able to both qualify for the RPS requirements, but also offset the existing system. If you have to continue doing emissions at 2030.

Markham Hislop: I’ve been doing quite a few interviews with economists and utility policymakers about electricity markets. It’s a very hot topic these days because those jurisdictions – Alberta in Canada, a number of American states and to  certain extent in Europe – have markets that are operating efficiently to a greater or lesser degree. There’s been all sorts of lessons learned and still more fine-tuning to do. Regional electricity markets have become a hot topic lately. There are already regional markets in your area, with BC and Alberta being part of those. Is there any part of your plan that includes expanding those markets and further developing them, bringing in different types of markets to fill in gaps in the current regime?

Ben Kujala: We’re focused on long-term planning, whereas obviously markets tend to be about short-term operations. We have some ways to simulate what would happen in the West if we did have more efficient markets that we’re going to be work into our planning.

A good example is the planning reserve margin. We need to build enough generating capacity for our peak load plus some percentage, just in case. We’re very comfortable about that approach. If our forecast is wrong, we’ve got extra generation to make sure that we meet that peak. One of our theories is that with more efficient markets, we might be able to lower that planning reserve margin. That reduces the need to build new resources provide and provides some diversity as well.

But of course, any specific market is so detailed that I think to say, this is an organized market and this is not. And just be able to do a scenario and say, this is what it would be. It doesn’t work because

Every organized market I know of has different rules of engagement, different ways they’re set up, and different secondary markets (for example, ancillary services). The details matter a lot in terms of what you would project would happen in terms of planning. The best we can do is say, well, here are some things that an organized market could have an impact on and we’ll look at those areas.

Markham Hislop: I interviewed Severen Borenstein, who’s an economist at Berkeley and also sits on the board of the California independent system operator. Kind of a unique perspective that he has and he’s a big proponent of demand management. For example, allowing utilities to turn people’s air conditioning down when the system is strained. so they use less electricity when there’s high demand. He says demand management is being enabled to a large degree with new technologies and I’m wondering the extent to which those technologies are playing into your planning process.

Ben Kujala: We always start with a  world where we have a potential for demand response or demand management, as you’re talking about, and the potential for conservation or energy efficiency. Demand response in our last power plan was a great resource. It provided capacity in a system where you had a lot of surplus energy, but you needed capacity, when you’re building a lot renewables. And that tends to be the way systems are going especially prior to retiring a lot of traditional thermal generation. You will have a system with a lot of energy in it and you need capacity and demand response is an excellent resource for that.

Because of course our system, depending on the water year can have a very different amount of hydrogeneration in it. And so it might be in a really wet year, you know, we’re not going to use these programs at all, but we want to make sure that they’re available for that dry year. And I think it’s shown a lot of value because it’s, it’s not super expensive to build, it’s way cheaper than building a peaking gas plant and letting it sit there for 10 years without ever being used.

Demand response also has the ability to easily scale up and scale down.

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