Title: Distributed Generation 2.0: What You Need to Know
Speakers: Marc Machlin and Katherine O’Konski
Marc Machlin (00:08):
Kat, great to see you.
Katherine O’Konski (00:09):
Great to see you too, Marc. It’s really exciting to be able to talk to you today about distributed generation. I know you have over 40 years of experience on regulatory matters, including distributed generation, so it’s going to be a really interesting conversation.
Marc Machlin (00:24):
Likewise, I’m looking forward to hearing your feedback. I know you have a few less years of experience, but maybe close to a decade or so, and looking forward to talking it through with you.
Katherine O’Konski (00:35):
Absolutely. So let’s get right into it. Can you tell me what is distributed generation?
Marc Machlin (00:41):
So distributed generation in its simplest form is onsite generation. And what this means is it’s generation that supports the operations of the host off-taker, which could be a manufacturer, a hospital, a university, or anyone else, any other kind of entity that uses energy. So often these are solar projects or battery storage projects, co-generation projects. They can be off the premises because there is something called virtual net metering in some states. So in some states, the regulatory system allows you to site within a certain number of miles of your facility and treat that as if it’s onsite generation.
Katherine O’Konski (01:33):
Okay. So I think I understand onsite — like, for example, solar panels on people’s houses in my neighborhood. Would that be a form of distributed generation?
Marc Machlin (01:42):
Absolutely a form of distributed generation. And those folks are getting some of the same benefits, right? I mean, the industrial and commercial users that we normally see, they’re getting increased resilience, they’re getting reduced costs, they’re shrinking their carbon footprint. And those same benefits can go to those individual homeowners who may also have relatively simple forms of distributed generation.
Katherine O’Konski (02:14):
So what about the offsite example that you just described? What would that look like?
Marc Machlin (02:20):
So what you could have is a manufacturing site where there’s not sufficient room on the site for a large solar array. So the developer or the manufacturer would find a site usually within three or four miles of the plant and the utility would treat it as if it was onsite generation, meaning it would still be eligible for net metering in most states and it would still be treated as if it was reducing your usage of power from the grid.
Katherine O’Konski (02:57):
Okay. And really quickly before we move on, you mentioned net metering. What’s that?
Marc Machlin (03:01):
Net metering is a benefit for onsite generation and what it is is if the generation unit produces more power than the host can use, the power goes back to the local electric utility and typically they would pay the full retail rate for the generation component of their services. And that’s a benefit because with any project, there could be particular days of the year where it generates more power than the host is able to use. And the retail price is obviously far more beneficial as a credit than the wholesale price would be. And there are typically various limitations and conditions on net metering and not all states have net metering, but it is an important part of the regulatory regime.
Katherine O’Konski (03:56):
And is distributed generation growing?
Marc Machlin (04:00):
It absolutely is for a number of reasons. The tax incentives and the Inflation Reduction Act, the desire on the part of users to shrink their carbon footprint and the desire for cost savings. So most of our commercial and industrial off-takers or our universities and hospitals, they want to achieve all three of those things. They’re trying to be greener. They’re trying to reduce their costs and they’re trying to be responsible citizens. And so distributed generation, especially renewable distributed generation, is one of the few ways they have to achieve those goals.
Katherine O’Konski (04:41):
So you mentioned tax incentives just now. Is it expensive to put in distributed generation and are those tax incentives helping that? I imagine it’s an industry that’s growing a lot right now.
Marc Machlin (04:55):
Yeah. The tax incentives are huge. So they vary some, but think about it as if the federal government through the investment tax credit would typically pick up at least 30% of the cost. And the host off-taker isn’t necessarily the recipient of the credit because often there’s a third party developer that owns and operates the renewable asset. But either way, one of the parties is able to get the investment tax credit. There’s accelerated depreciation as well. And there are state tax benefits as well — that varies from state to state, but sometimes there are exceptions from property tax and other kinds of incentives built into the state laws. And then lastly, the last piece of it is renewable energy credits. So in many states, if I build a solar project, that project produces renewable energy credits, which are marketable. And if the parties choose to sell those, that also helps to defray the costs of the project.
Katherine O’Konski (06:04):
Okay. So I think you’ve alluded to several different parties in a transaction that involves distributed generation. It seems like there’s the host, but there might be some other parties involved as well. Can you talk a little bit more about that? Who are they and how are they benefiting?
Marc Machlin (06:23):
So if you’re the host, you don’t necessarily have to have a third party developer or owner-operator, but it’s very common that you will. And so a third party developer supplies the capital, builds, owns, and operates the project. And I’ll just use a solar project — it could be solar, it could be battery storage, it could be co-generation. But they build, own, and operate it. They take the construction risk. They take a lot of the permitting and interconnection risk. But your obligation as host off-taker is to buy the output. So if it’s a solar project, you buy the electric power. If it’s a co-generation project, you would buy electric power, chilled water, steam — whatever those outputs are. Typically the host is obligated to purchase 100% of the output. And typically the host is obligated over a 15 or 20-year period, sometimes a little less, sometimes a little more.
But it’s an obligation to take and pay for a very long period of time. And those contracts, those power purchase agreements, leases and related agreements then allow the developer to secure the financing of the project based on the credit worthiness of the host off-taker.
Katherine O’Konski (07:57):
Okay. This is maybe a little bit of an aside, but you mentioned interconnection risks just there. I know from the transmission side of things, we’re facing huge delays and interconnection can really be a big challenge. Is that what you’re seeing at the distribution level?
Marc Machlin (08:14):
You do see interconnection risks and challenges from time to time. And what it is, is there could be parts of a local electric utility’s distribution system where there’s already a substantial volume of renewable energy on that portion of the system. And so to secure the interconnection, the local electric utility might say, “You need to fund some upgrades on our system.” And that then presents delays, it presents costs. And so there can be challenges there. The good news is we see that maybe five or 10% of the time. And many of the projects just go right through. And part of that is the size. So unlike a utility scale project, which might be 500 megawatts, many of these projects are one to five megawatts. So the interconnection challenges are lessened. And usually developers have pretty good information in advance whether they’re in a congested area on the utility system.
And so they know how to pick sites where there’s less challenge there. And then lastly, what I’ll say is in many states that are trying to promote renewable energy, there are time limits and procedures placed on the utility to encourage the relatively rapid processing of those interconnection requests. So they won’t just sit there for years as they might at some regional transmission organization.
Katherine O’Konski (09:57):
Got it. And are we seeing distributed generation throughout the country or are there areas where it’s becoming more prevalent?
Marc Machlin (10:07):
Yeah. I think we see it more in the states that are promoting green energy. So if I look at the projects we’re doing, there’s probably 15 or 20 states that are the most active. It doesn’t mean that it’s impossible in those other states, but states that have renewable portfolio standards, that have zoning laws that are conducive to these kinds of projects, states that have interconnection rules established by the PUC that favor renewable energy — all of those can be a factor in it. So it’s easier to do these projects where there’s a favorable political and regulatory climate.
Katherine O’Konski (10:56):
That makes sense. Speaking of regulatory and political climates, what changes are you seeing in the distributed energy industry?
Marc Machlin (11:07):
I would say one change we’re seeing is more battery storage. And that’s battery storage either standalone or coupled with solar. And there’s sort of renewed attention to the ways in which battery storage can be used. So battery storage can be good for resilience — when the grid is creating poor quality power or there’s a brownout or blackout, it’s a temporary source of power. It can be used in peak shaving. So if you have a large industry and you can reduce the peak usage during, say, four or five hours of the year, you can reduce the electric cost for that facility on an annual basis. So they can be used for peak shaving and they can be used for demand response programs. So all of those are revenue sources for battery storage. And they fit well with other onsite generation.
So you can have solar, but of course solar doesn’t really produce power at all hours of the day or at all times of the year, not with equal efficiency anyway. Whereas the battery storage is hopefully always there for you.
Katherine O’Konski (12:24):
At the transmission level, we’re also seeing a lot of storage interconnecting alongside solar and wind units. And that’s just becoming more and more prevalent. And one of the advantages to that is that sometimes it’s easier to interconnect a surplus storage project like that. I don’t know — it sounds like interconnection may be a little bit less of a challenge, but are there any ways to speed up interconnection if you’re adding a storage project onto an existing?
Marc Machlin (13:00):
Not that I’ve seen a lot of. Yeah, not that I’ve seen a lot of, but I like the idea. And I think that the state regulatory rules haven’t always completely caught up with storage. So a lot of these rules that the PUCs have in place really trace back to the beginnings of PURPA, and they haven’t always been updated. Now, some states have been updated to take account of solar. But the rules still need to be tweaked some for battery storage. And that reminds me that battery storage and ancillary services — an onsite battery storage facility, and I assume a utility scale battery storage facility, can also be used to produce ancillary services, which is another revenue generator.
Katherine O’Konski (13:52):
And what are ancillary services?
Marc Machlin (13:56):
I hesitate to describe them all. But one might be voltage control. Another might be frequency control. So the power on the grid has to achieve certain qualitative standards. And so if the voltage starts to fall, for example, they would want to inject power to create higher voltage. Or they may want to inject power to restore the frequency to the appropriate levels. So it’s basically services that help the grid be operational, as opposed to energy itself. So energy itself is what the end users are using. The ancillary services are really products or services that help keep the system functional.
Katherine O’Konski (14:49):
Absolutely.
Marc Machlin (14:51):
So, which feeds into another question I have for you.
Katherine O’Konski (14:54):
Okay.
Marc Machlin (14:54):
So what, if anything, is FERC doing that relates to distributed generation?
Katherine O’Konski (15:04):
FERC has taken a few actions that facilitate the participation of distributed generation in the wholesale markets. One of the big ones is Order 2222, which FERC issued in 2020. And that order directed regional transmission operators and independent system operators to create rules to allow distributed generation to participate in the wholesale markets through what are called aggregators. And the idea there is that the aggregator would essentially combine distributed energy generation from various sources and that combined product would be what is participating in the wholesale market.
Marc Machlin (15:54):
Do you expect that there would be a lot of variation among the regional transmission organizations in how they authorize this kind of aggregation of distributed energy resources?
Katherine O’Konski (16:10):
Yeah, absolutely. These are new rules that are being implemented in each region throughout the country and the rules have to be integrated with whatever market rules existed there. So each RTO is kind of on their own implementation plan. And in fact, the timelines for actually implementing these rules to allow DER participation are on varied timelines. Some RTOs have already started implementing the new rules and some aren’t planning to until as far out as 2030. So I think it’s an area that’s very much still in flux.
Marc Machlin (16:48):
I want to ask you about FERC Order 745. What can you tell us about that order and its impact in this area?
Katherine O’Konski (17:01):
So Order 745 was issued in 2011. And it allows generation participating as demand response in the wholesale markets to receive the wholesale LMP.
Marc Machlin (17:15):
Let’s talk a little bit about demand response programs and how they relate to distributed generation. And then let’s move from there into what FERC’s role might be, if any, in promoting the demand response programs.
Katherine O’Konski (17:34):
Sure. So demand response at a high level is essentially the promise to cut demand from the grid when asked and the ability to be compensated for that. So this is happening at the retail level, for example. An industrial customer might have the ability to reduce their load on the grid if their operations are flexible and could be compensated for the ability to maybe shut down their operations and reduce that load for a certain period of time. So that’s happening at the retail level and it’s also happening at the wholesale level, where aggregators, kind of in the way I described with Order 2222, are combining many different market participants’ ability to reduce load and participating in the wholesale market with that combined promise, as it were.
Marc Machlin (18:32):
And so if you had battery storage, for example, on your site and you were a manufacturer, you could turn to the battery storage as a way of reducing your power consumption from the grid and thereby benefit directly or indirectly from these demand response programs.
Katherine O’Konski (18:54):
Yes, exactly. And FERC, in issuing Order 745, allows demand response to be compensated at the same rate that energy would be compensated. So you can participate in the market with your promise to cut your load when asked and receive the same LMP that energy participating in the market would receive.
Marc Machlin (19:15):
So regulation creating revenue. That’s what we like.
Katherine O’Konski (19:19):
That’s what we like.
Marc Machlin (19:19):
Kat, thank you for joining me in this discussion today. It’s been great.
Katherine O’Konski (19:27):
Yeah, thanks, Marc. Really enjoyed hearing about distributed generation and your expertise in the industry.
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