Summary
In this episode of InDERmediate co-hosts James Gordey, Pamela Wildstein and Ben Hillborn are joined by special guest CeCe Coffey to unpack the Wild West of interconnection, FERC, Order 2023 and its potential impact on distributed energy resources (DERs). They talk through the role of FERC in energy regulation, how orders get named, then explain how interconnection works simply and highlight the problems with interconnection today. Finally we summarize order 2023, its impact on DER’s and brainstorm what might come next.
Note: This episode was recorded before FERC granted an extended compliance deadline.
Episode chapters:
(1:33): Ice breakers
(3:38): FERC intro
(4:53): Interconnection stakeholders
(8:35): How does interconnection work?
(12:51): Interconnection studies
(16:11): Interconnection x FERC
(19:05): Naming FERC Orders
(23:54): Prioritization
(27:12): Interconnection problems
(35:05): What's in FERC 2023?
(38:07): Transmission provider penalties
(42:44): Commercial readiness
(44:46): Interconnection hipsters
(51:51): FERC 2023 x DER’s
(54:42): FERC order lifecycle
(1:00:41): What’s next?
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Relevant links we found helpful
THE ACTUAL ORDER: https://www.ferc.gov/media/e-1-order-2023-rm22-14-000
https://www.eenews.net/articles/ferc-approves-historic-rule-to-address-renewables-backlog/
https://www.utilitydive.com/news/ferc-interconnection-queue-reform-spp-miso-pjm-rto/689965/
Background: https://www.utilitydive.com/news/energy-transition-interconnection-reform-ferc-qcells/628822/
https://emp.lbl.gov/sites/default/files/queued_up_2022_04-06-2023.pdf
Site to track interconnection queues across all the ISOs and a few utilities as well by Steven Zhang
Music
Our incredible intro/outro music is the song Ticking, by artist TIN
You can stream the whole song and the rest of their catalog here:
Episode transcript
What are those things that we have now available that are renewable
That can be worked in quite a different way into the economy of the United States
Which are concerned primarily with the design of nuclear power plants and this type of thing
We do not know what the magnitude of the side effects will be
Hi, I'm Pamela Wildstein. I'm Wyatt McAdamski. I'm Ben Hilborn. I'm James Gordey
You're listening to InDERmediate
to Intermedia, the place for people trying to get into
or already working on distributed energy resources
and clean energy.
This is the podcast that makes it easy to learn
how the grid actually works beyond the office.
Hey everyone, welcome to the show.
I'm your co-host, James Gordey.
Today we have Pam.
Hi Pam.
Hi.
And today this is gonna be a bit of a two-part episode.
So in part one, we're gonna cover FERC
and interconnection kind of generically.
And then in part two,
we're gonna cover the hot off the press
in energy terms for quarter 2023.
And then kind of after that,
we're gonna spend some time and look forward
to where things are going from here.
And joining us on the show today
to help us level up our game,
we have Cece Coffey.
Cece, thanks for joining us and welcome to the show.
Thanks, James.
Happy to be here with you and Pam
and to talk about interconnection.
Okay.
Okay, so just jumping into it, we always like to start with some icebreaker CC, so play
along with us a little bit here.
You personally, this is a show about learning about clean energy and DERs in general.
How do you learn about clean energy?
Well, thanks for asking.
Honestly, it's something I've thought a lot about.
When I got out of undergrad, I moved down to DC, which is a great place in the country
to be working in energy, but I was really trying to learn as much as I could as quickly
as I could.
So I was reading Utility Dive and other trade press, I was attending conferences and panel talks,
and I also joined the Clean Energy Leadership Institute in 2016 and have stayed involved
with them since. So I think for me, learning about energy isn't just reading, it's also
talking with people. And that's why I'm excited to be on the podcast and also to have been involved
in DER Task Force, because I think when everybody gets together, we have some pretty cool ideas
about the future of clean energy. Yeah, no doubt. Always the obligatory
So moving on to the second one then, there's a lot going on in energy.
What portion or topic are you most interested in right now and learning about?
Yeah, there are a few, you know, on a large scale, I've always been interested in how high voltage transmission gets planned and built.
You wouldn't think of that being clean energy necessarily. But, you know, there are a lot of examples going back to CREZ and Texas and others about how building transmission really gets new generation online.
And on a smaller scale, I've been really excited to see how clean tech companies have been
able to unlock distributed energy resources, not only to provide demand response, but also
dispatchable power, following Octopus and others who've been doing virtual power plants.
And then one thing that I don't know that much about, but I'm curious to follow is just
this kind of rebirth of nuclear, whether it's large scale commercial or the small modular
and micro reactors.
I think those are so interesting and kind of the way that they can do community energy
maybe in the future.
And then I know we had asked you ahead of time, Cece, for some deeper dive resources
if people are curious.
So for anyone following along with the podcast and online on the show notes, we'll put all
of those links there and links we found helpful.
So kicking things off, at a high level, can you explain what FERC is and why they have
authority?
We touched a little bit in a FERC overview that Pam gave on our great overview episode,
but good to unpack it more here.
Okay.
That's great to know.
And for everybody who's listening who I haven't met yet, I'm in law school right now, so please forgive the brief detour into legal history.
But I think it's important to understand what FERC is and how it came to regulate the transmission system.
So going back more than 100 years, actually, Congress in 1920 authorized what was then the Federal Power Commission to oversee the nation's hydropower resources.
And the Federal Power Commission was formally established in 1930.
But it was five years after that, in 1935, when Congress passed the Federal Power Act,
which transformed the Federal Power Commission into an independent regulatory agency, and
it granted that agency the authority to regulate, among other things, the interstate transmission
system.
And that's really generally the same jurisdictional authority that FERC, the Federal Energy Regulatory
Commission, has today.
Its interpretation of that authority has changed and evolved as the system has changed
and evolved.
But, you know, on the transmission side, at least,
BERC regulates all transmission between states
and as kind of by virtue of that,
the transmission that happens at high voltage
with both power systems.
So who are the stakeholders in the interconnection process
that Order 2023 is gonna be regulating?
Sure, so there are actually a number of players here.
It's who you'd guess, right?
The project developers.
Those are the people who are building, owning,
and financing new power plants, new generation resources.
And it's the transmission providers who are receiving the request of those project
developers to hook up to their system.
But there are also other indirect stakeholders.
Transmission customers should care because they're the ones who ultimately pay the costs
that the transmission providers pass along.
And we're transmission customers ourselves.
Those rates that we pay to our local utility cover what the utility pays to the transmission
provider to get energy off of their system.
And states should also care.
States have policy priorities.
they're trying to get a lot of different types of resources built and if those
resources are you know proposed but can't actually get interconnected and
can't reach commercial operations that's really going to slow down states who are
trying to maybe meet their 100% renewable energy goals. And in this case
just you know because when I was first reading through the order I got a little
confused on this. Transmission providers in this case are both in restructured
and non restructured areas right so it's both the independent system
operators, such regional transmission organizations, and then also monopoly utilities.
Yeah, that's exactly right. And I should say, you know, you all are pretty familiar with this. I
know it's a bit of an alphabet soup, but Pam, when you're saying restructured areas of the country,
you're talking about those parts of the country where generation is separate from who owns the
transmission and distribution systems. And as you pointed out, those are operated in many cases by
entities called independent system operators or regional transmission organizations,
who not only dispatch the systems but also operate the markets for buying and selling
energy in those regions.
But there are parts of the country, as you mentioned, that are not restructured.
They still have, for the most part, vertically integrated utilities that own generation,
transmission, and distribution.
And there are also transmission providers and need to comply with these rules.
Because one thing that I could have mentioned earlier is that for jurisdictional authority
over transmission, I said with the interstate system, but really any transmission provider
over a certain megawatt threshold is jurisdictional and needs to comply with some of the transmission
related rules like order number 2023.
James, you can say it.
What is restructured and non-restructured translate to for you?
Yeah.
In my mind, what is it?
No.
Deregulated and regulated.
Pam and I had a whole conversation where we were trying to simplify this in people's
mind and at the end, Pam was actually using my words, but then we mind tricked her into
And that was my question too, just to like unpack transmission providers.
So Pam, we're on the same page today.
Totally.
I think the way I think about it, honestly, Pam, we can come back to this, is just that
whoever physically owns the grid and that grid is a patchwork of different systems that
are owned and operated by different entities.
And I think sometimes it can get confusing to think about, well, who's in a region and
who's operating independently, because all of these systems need to be operating at
same frequency and overseen by the same reliability regulators in the end, that being FERC and also
NERC, the North American Electric Reliability Corporation. But I think it's worth noting that
even though they all operate together as one seamless machine, they're owned by different
entities, and those different entities are the ones who are responsible for processing requests
to put new generators onto their systems. So those are the transmission providers that I'm
talking about. Those are also – this will come into play later – the entities that maintain
open access transmission terrace. Those are the sets of rules for not only interconnecting onto
the transmission provider systems, but also for taking transmission service as a transmission
customer. So at a high level, Cece, this is covered in other places, but I think it's helpful to give
people the foundation. How does interconnection work today? We hear about it. We hear about the
fact that there's so much new projects in the interconnection queues that it's more than is
actually on the grid today, but like, can you speak to what it is at a high level for us?
Yeah, absolutely. And I totally agree. I think it's easy to get bogged down in all of the details
about interconnection, but historically interconnection is just a three-step process.
It has a number of sub-steps, but I think for me, it helps to keep track of these as stages.
So the first step is that a prospective interconnection customer submits an
interconnection request. And what that means is you have a new facility, you want to interconnect
connect it to the grid, and you need to submit a request to the transmission provider who
owns and operates that grid to start the whole process.
And then the second step is that that transmission provider assigns a queue position and conducts
technical reviews.
And this is something that we'll talk a lot more about later in this episode, and especially
the next episode, is what is a queue?
And honestly, you can think about it like waiting in line at the grocery store.
The first person in line lines up, and the next person in line gets in line behind them.
And so, that queue is something that we talk about when we talk about power plants
interconnecting to the grid. It's the same sort of wait-your-turn system.
And then, the third step is that both parties, both the prospective interconnection customer
and the transmission provider, once the transmission provider has conducted all of
those technical reviews and determined what's necessary physically from an engineering
sense to interconnect that power plant into the grid, then they execute an interconnection
agreement, which is a bilateral contract where they both make certain commitments,
and that interconnection agreement is what green lights
the interconnection of the new resource onto the grid.
And at this point, there's no guarantee
that you'll generate power, right?
That comes later through whatever,
I'll stay with restructure,
because that's what I know the best,
that would come to the market.
Yes, definitely.
I mean, your dispatch instructions, again,
will come through the market.
There may even be a different provider.
It may not be that transmission provider
who tells you turn on or turn off,
but really the interconnection agreement,
again, I think of it as the green light. You're cleared for takeoff. Everything's in place that
needs to be in place for you to start injecting electrons onto the grid. And there are a number
of different factors that will determine later how often you do or whether you do or for how long.
So roughly how long does this interconnection process take from beginning to end?
It's honestly pretty astounding. The average right now is about five years,
although that number can vary a lot. It depends not only on the size of the facility
and the region of the country,
but also on the unique topology of the transmission system.
And I didn't get this number.
Researchers at the Lawrence Berkeley National Lab
put together a really comprehensive guide
to interconnection queues
that they published in April of this year.
I'm sure you all can link it for the listeners,
but LBNL has done a great job outlining
not only how long it takes
from interconnection request commercial operation overall,
but how that varies in different regions of the country
and even for different types of resources.
That's crazy.
I did not know it was that long.
People would always complain about how long it was, but wow, five years.
On average, five years. My world is startups and technology. When you have an employee join,
you give them equity to vest because you want them to stay at the company for a long time.
And the equity normally vests over a four-year period. So it's less than an interconnection
queue average process. Less than an interconnection queue,
right. So if someone complains about how long it takes for their equity to vest,
You can just point them to this report.
Actually, this is not making it into toasters because of this podcast, we like to try to
translate numbers into the number of toasters, but it does take five years to do a PhD.
So it takes a PhD for this interconnection process.
Right now.
But as we're going to talk about later in this episode, that's a long time and it's
long enough that it's slowing down not only project development, but also safe policy
goals and so one of the goals of broader interconnection reforms of which order number 2023 is a huge
part is going to be shrinking that five years until a more manageable amount of time.
Maybe we can make it into two years, which would be a master's.
No guarantees, but we're well underway. That's, that's for sure.
Chipping away at the problem. So one thing that I think is a little bit confusing to
folks not as familiar with the interconnection process. These studies right we need to study
it and we need to study it again.
And if one little variable changes, we need to do some different studies.
Maybe, could you kind of unpack these interconnection studies?
Like why do we do them and what do we learn from them?
Absolutely.
So, uh, again, historically this was done project by project.
And as you alluded to, uh, if that, if that line changed, if that queue
changed, if someone ahead of you decided to go back, go back and get
another item for their grocery cart, then all of a sudden everything changes.
And I think it helps to just start from a really high level.
we study the interconnection system to determine whether there's enough spare transmission capacity
to accommodate a new generator, or whether the system will need to be upgraded before
new resources can interconnect without compromising reliability. So what that
means is essentially, is there enough headroom on the existing transmission system? Are the
capacities of the existing transmission lines in the area where you're trying to put a new
generator at capacity, or is there space? Is there additional megawatt capacity that would allow
more electrons to be pushed across that line routinely. And if there is enough space, then
it really speeds some of the interconnections. The interconnection generator will still have to
go through studies, but they may not be assigned those costly network upgrades that you may have
heard about that can really jeopardize a project's economic viability. And if there isn't enough
space, then that's where network upgrades, as we're saying, are assigned. And a network upgrade
is essentially when an interconnecting generator is told that the existing transmission system
does not have enough spare capacity to facilitate their participation. And so if they do want to
get built, they're not only going to have to build their own facility, they're also going to have to
build or at least pay for the transmission provider to build upgrades to the transmission
system to make sure those electrons can get from power plant to customer.
Yeah. And then like one tricky thing I was listening on a Dr. Voltz podcast was talking
about like, it's almost like musical chairs or on luck of the draw, where like, if you are the
person that is going to require the transmission upgrades,
then you get stuck with the cost.
And so people are trying to not get stuck with the cost,
in a sense, and that causes a lot of people to,
going back to the grocery store analogy,
maybe get out of line if they realize
they're going to have to pay extra for their bread.
Yeah, I may have pushed the grocery store analogy too far,
but I think it's something to make it
a little more concrete, right?
And I totally agree.
The musical chairs piece was one of the big reasons
why FERC and Order Number 2023,
and several regional transmission organizations
on their own before they're required to decided that this one-by-one processing wasn't just inefficient,
it was also creating incentives for people to, if not intentionally game the system,
at least deal with delays and cascading restudies that led to some of these really,
really long gaps between interconnection requests and commercial operation.
And so I think one big change, which we'll talk about later, was doing the whole process by group by group
instead of one by one, meant that there was a little less of that luck of the draw, that
you would be assessed for how many network upgrades needed to be built as a group collectively,
and then the cost of those upgrades would be shared.
And so it was a little less that you would get really lucky and get away with having
headroom on the system and not have to pay anything, and it was also less likely that
you would get stuck with a bill for 10 people's interconnection.
Going off that, what has FERC done in the past?
What's the history of interconnection?
And what are the FERC orders that it relates to?
Sure, so it's really not as long a history.
We talked about the history
of the Federal Power Commission earlier,
and that's a hundred year period of history.
But the process of FERC managed interconnection procedures
is actually pretty short.
So before 2003, interconnection procedures
were fairly inconsistent across the country.
Each transmission provider generally had the authority
to determine the procedures that it thought could work for its own system and to manage
that set of procedures. But then in 2003, IEEE established technical standards for the
first time, first for small generator interconnection. And the same year, FERC issued Order No. 2003,
which established federal interconnection rules for large generators, and you can look
at those online. But for the next 15 years, FERC largely approved incremental changes
the transmission provider's interconnection procedures. And FERC also established rules
guiding a provision of reactive power and frequency response from interconnecting generators,
things that we can all think of as really needing to maintain the reliability of the system more
so than managing this queue process. But in 2018, five years ago, FERC issued its next major reform
of interconnection procedures. That was order number 845. And 845 was designed to enhance the
interconnection process, both to account for changing technologies and also to facilitate
additional generator interconnections.
The energy transition was already well underway in 2018, and these queues were getting longer,
wait times were getting longer, and so FERC took action to try to raise the floor and
make sure that transmission providers across the country were complying with certain more
rigorous minimum standards to make sure that they were trying to process generator interconnection
requests.
But 845 did leave several gaps.
It retained the serial queue process that was contributing to queue backlogs, that one-by-one
processing that we've been talking about.
And 845 also maintained a standard that transmission providers only needed to make, quote, reasonable
efforts, unquote, to comply with study deadlines, and that's important.
That means that there's really no binding deadline by which the transmission providers
need to finish their studies, and that really contributed to uncertainty for interconnecting
power plants about exactly how long it was going to take to figure out both what their
costs would be and when they'd eventually be able to start reaching commercial operation.
And I guess one more thing I'd say about 845 is it included pretty anemic penalties to back up
those flexible deadlines. If transmission providers didn't turn around a study in the 60 days that
were required or 90 days that were required, it was kind of a shrug, you know, okay, well,
try better next time. And that was something that also really contributed to some of the
And as you can see, these are problems that FERC was realizing as, as we were heading into 2022, 2023, we're maybe going to need to be addressed again.
Yeah, real quickly before jumping into the next question.
Totally okay if we don't know or if it's random or whatever the answer is, but like, can we speak a little bit to how these like numbers and the names of these orders get generated like sometimes.
Favorite question.
Order 2003.
Favorite question.
Do you know the answer like is this Pam do you have a surprise like I mean forward right the tear does choose I know that actually former commissioner and chairman Chatterjee cleared this up with 2222 right the famous the er aggregation order because he explained that those numbers were actually a combination of the birthdays of members of his family and and told everyone publicly that the order number is up to chairman's discretion 2003 I think you guys can see it was issued in 2003.
I think that one's pretty straightforward.
Another pretty common one is order number 888, which ensured open access to the transmission
system, was named after the new building that FERC moved to in D.C.
It used to be on North Capitol Street, but it moved one block over to First Street Northeast
at 888 First Street.
So that was one that commemorated the move.
So sometimes they're fun, sometimes they're random, sometimes they're tied to the year,
but yeah, no serial order for those.
Wait.
2023?
Is there anywhere?
Yeah, 2023.
2023 came from because this was such a big deal came from 2023. Yeah. Yeah. That's yeah.
Wait, is there anywhere online that lists all the orders and how they got their name?
No, I don't have a document though, where I keep track of it though. Oh my gosh, Pam,
we need to publish that. No, it's just like a random like Google docs somewhere that I started
as a joke. That's what InDERmediate is all about. What would Indy want you to do, Pam? Do we want
to get this out here? Is it just your own Google Doc?
It's my Google Doc. Actually, it's not my own Google Doc. It's
at the bottom of my typed up law notes from when I took energy
law. But I will say that when I learned to order 888, the exact
like line when my professor opened, you know, opened the
discussion on it was, you know, it was an important order,
because they named it after their address. Yeah. It seems
when you look at the history of the interconnection processes
and for the amount that FERC's regulating it,
that they're almost moving towards
more standardized processes.
And I'm thinking in the context of RTOs,
like the RTO taking more of a planner role.
And I think Clements brought this into her discussion too.
Who's Clements?
Sorry, Commissioner Clements.
I'm thinking of how back in 2000,
there was this goal of the ISOs transitioning into RTOs,
which is where the name difference comes from.
And the RTO was gonna be this large centralized
system operator, system planner,
And the switch to, you know, the R in it was that they were going to plan the transmission system and they were going to take a much stronger role in having the centralized system that they were going to operate.
And when you start to, when you go from, I didn't realize that it was in 2003 when they started to do these interconnection procedures and I guess maybe an attempt and maybe it was just because of IEEE but like an attempt to make them more consistent.
and that just feels like that push
to have more centralized planning entities
for a more complicated system.
I think that's definitely part of it.
And I can't say that these are connected.
This is just totally, you know, out of left field here.
But what else was happening in 2003
was the great Northeast blackout.
I mean, there might be other things that were happening
that led FERC or others.
I think 2003, the process for that rule
was already well underway at that point,
but may have added some urgency to figuring out if there were additional resources that were needed
on the system, as there may have been, right, in 2003, as loads are continuing to increase and more
people are looking to interconnect. It might have just been more necessity. And I think one other
thing that's important to keep in mind is that the ISOs and RTOs themselves are pretty new. I mean,
the New England Power Pool, I think, was the first one in the mid-1990s, and then
NISO organized and others over the course of the late 90s and early 2000s.
And so I think one of the reasons that may have prompted 2003, and again, this is just
my opinion, is that you have all of these organized markets that are still pretty new.
And I think FERC was still trying to figure out what its role would be and how it could
help ensure efficiency in the interconnection process and also provide some certainty to
interconnecting generators.
And to your point about standardization, I think in theory, one reason why you might
want to have standardized processes is to remove an incentive for power plants to want
to build only in one part of the country, to make sure that any resource that was built
across the country would generally have the same expectations and would generally be put
through the same paces in a way that might kind of democratize access to the grid.
I think that's what I would guess it would be, but I have no idea.
Yeah.
A question I had, if I could ask.
So FERC orders come out, it seems, like I've been in clean energy maybe three years now,
So, you know, we've had 22-22 and 20-23 since I've been here, you know, kind of following it since COVID.
Is it, like, it's probably transparent, but is it worth talking about, like, how they decide which issues to tackle and orders to do and what order?
Because obviously there's a lot to work on, and I'm sure there's some big process by which, like, orders get issued.
But curious, like, how that prioritization and, like, order creation process happens.
It's at the discretion of the chair, right?
Yeah, it is.
That's what I was going to say.
Oh, sorry.
And you've heard some recent chairs talk about this, right?
Chairman Chatterjee, I mentioned.
Chairman Glick has been pretty outspoken about his priorities, and now Acting Chair Phillips
has also been clear that getting Order Number 2023 out was a priority of his.
And so while the entire commission works together to study what updates to existing procedures
may be needed, the ultimate final rule process is really guided by the chairman and their
priorities.
That's fair. And my understanding and research leading up to the show is that there's four
or five commissioners and then one chairman within that group?
Yes. Five commissioners is a fully seated commission. Although, as you may have noticed
in recent years, depending on term ending dates and reconfirmations and even nominations
from the president that have lagged behind some of those vacancies, the commission's
often sat at three or four commissioners,
but a number of the commissioners,
the current and former have said publicly
that the commission functions best when it has all five.
And so I think that's something that those of us
who work in energy law and energy regulation like to see
is the ability to have five commissioners
because not only does it lead to stronger,
unanimous orders on rulemakings and general adjudications,
but it also gives a little bit more room for compromise
and for really working out
some of the nuances of these issues.
As you saw with order 2023,
all four commissioners voted in favor of that order.
But through their concurrences,
you can see that they may have had
different policy priorities or
different conclusions and
different parts of what they were approving.
Yeah, and I'll emphasize this again in part two.
I thought it was very impressive that this ended up
being a 4-0 vote but you
should definitely go read the concurrences,
because that's where you see
the commissioners start to have
their own opinions and really where they get to
shine. And you get to see all the interesting nuances and what might happen in the future.
Definitely. And for anyone who doesn't know, what is a concurrence?
Concurrence is a yes vote. A concurrence is saying that I conclude in the ultimate
outcome of this order or this rule, but I have either slightly different reasoning or I have
other facts or considerations that I want to introduce into the record. Or I might, as Pam
said, want to highlight areas for future work. But a concurrence, it's important to remember,
is a full yes vote. It's nothing short of a normal agreement.
Yes, and. Yes, and. That's a good way to put it.
Okay. It's the stand-up comedy of orders.
Yes, and here's 15 pages of my opinion. I mean, hey, if the mic's turned on. So
kind of wrapping up part one here. So you see, could you help us understand,
like, I think a lot of people trying to get in, maybe trying to help with this problem,
you know, from many angles are curious, like, what are the biggest problems kind of understood
or explained in a simple way with the current interconnection process?
Definitely. So I think one of the largest challenges for all of the stakeholders that
we talked about earlier, that's not just project developers and transmission providers, but
also transmission customers and states, it's uncertainty. So the marginal cost of energy
is falling. And, you know, that's something that we've talked about, there are more clean
energy resources on the system, solar and wind and other types of renewables tend to
have a zero marginal cost or near zero marginal cost of operating.
And with that marginal cost of energy falling, more projects are operating on thin margins.
When they're looking to interconnect, let's say you have a new solar facility that's looking
to interconnect, they're going to make some money from selling energy, and they have
some fixed costs that need to be recovered through other means, whether it's by contracts
or participation in a centralized capacity market.
But if they're assigned really hefty transmission upgrades, network upgrades, that's going to
cut into their profitability and may even mean
that it doesn't make financial sense
for them to interconnect.
And so dealing with this uncertainty
and especially dealing with uncertainty
around network upgrade costs is a really important part
of making sure that new resources
can be hooked up to the system.
And for transmission providers,
this cascade of generators withdrawing from the queue,
not only generated just an unmanageable number of restudies,
but also led to cost allocation problems.
I think we teed this up or hinted at this
at least a few minutes ago.
But if you, for some reason, were in a queue and you hadn't been assigned many network upgrades
because someone right in front of you was going to build an addition to the system,
but they withdrew from the queue and they essentially took their money with them,
you might be hit with that upgrade cost, which you weren't anticipating.
And you may have now been further into the process of requesting your interconnection,
and it may not make sense for you to go forward.
And so when I say cascading restudies, it's because when one person pulls out,
But if you're dealing with each generator in turn, one by one, then when their costs
are pushed down to the next person in line, it can cause many different people behind
them to pull out as well.
And that leads to uncertainty, of course, for those folks who are interconnecting, but
also for the transmission providers, who are honestly doing a lot of work, doing the lion's
share of the work here, to continually re-study the topology of their system to determine
where there's existing headroom and to find out network upgrade costs.
And if that's changing every time someone pulls out, then it creates almost an impossibly
long process for them.
Yeah.
Thank you for walking us through that.
Would you say then, just to restate, right, that uncertainty and then kind of the unanticipated
like network or project costs that come from it are definitely like two areas.
And then the third is just given how that process plays out with uncertainty and then
people like pulling out, not pulling out, things like that, it just creates a lot of
work for the transmission providers and operators.
Yeah, definitely.
I think that's a good way to summarize it, right?
Uncertainty in cost, uncertainty in timing,
but then you're right.
It comes all down to this idea of the length of time
it takes to get from submitting that request to actually
reaching commercial operations.
So all of the delays kind of become their own problem
at a certain time.
Yeah, for sure.
I'm trying to think.
There's like obvious, you know, like cascade effect, maybe
ripple effect, like whatever you want to say. Okay, so just like so we know that's
the conclusion of part one where we talked about FERC and InConnection at a
high level. Now we're gonna move on to part two, which is where we're going to
focus on FERC Order 2023 and kind of some forward-looking ideas and
brainstorms the group might have. Wait, can I actually make one last point or
comment. That's also a question, so tell me if I'm wrong. When you think about the amount
of uncertainty associated with Generators withdrawing and the amount of time you might
spend in the queue and where you'll end up in the queue and all the uncertainty that
that would cause you as a company and a business or as a project developer, that probably really
limits the type of projects that can get built too, because the only people then that can
submit projects are those that have the capital on hand to deal with that uncertainty.
Yeah, that's a really great point. I think that's changing a little bit, and I'm definitely not a
finance expert. I'm sure there are folks you could bring on the show who can talk a little
bit more about this. But there are essentially some of these delays that become barriers to
project development, and it means that you have to have a lot of working capital in order to both
build these projects and to withstand the expected delays that come up at this point,
as well as to maybe put up more money
or at least more collateral to cover unexpected upgrade costs
that you may need to pay.
So yeah, I think your point is right,
that typically if you're a larger product
developer with deeper pockets, you're
going to have a better chance of withstanding
some of the uncertainties that was present in the one-by-one
process than you would if you're a small kind of mom
and pop developer.
Yeah, and you made some comments before about standardizing
things and driving more certainty in the process
to try and raise the floor, I think is a good way to talk about it and let more people access
the grid from an interconnection standpoint. Because it's not ideal, I think, at minimum
to say, okay, if you have deep pockets, then you can interconnect. But otherwise, it's kind
of a hit or miss process. Great if we can make it more certain.
Definitely. And I guess one other point that's important to note is that it's not just certainty
having these standardized procedures, it's also essentially removing the ability for
transmission providers to discriminate.
And we want to believe the best in everyone, right, but if you're a transmission provider
and you have your own resources, maybe, that are interconnecting onto your system, especially
in the parts of the country that aren't restructured, where there are more vertically integrated
utilities, part of the reason that 2003 and then after it, 845, and now 2023 were put
forward is to make sure that everyone's playing by the same rules and that if you own a transmission
systems that you have publicly available transparent procedures that any generator can
follow to get connected onto your grid. And then the flip side of that is as a transmission
provider that you follow those procedures in a non-discriminatory way. And what that means is
that you process the interconnection request, you conduct studies, and you execute or sign
interconnection agreements with third-party power plants in the same way and on the same
timeline that you would do for your very own affiliates. And so I think that's something to
always keep in mind in the back of your head when you're thinking about energy is that there are
those competition and maybe sometimes anti-competitive urges. And so a lot of the
things that FERC says to regulate and state public utility commissions do to regulate
is to remove both the opportunities and the incentives for any preferential treatment.
Yeah, I mean, it's the real world. I'm almost thinking about like,
you know, every market is different, of course, but like to the extent that you can make
the across all market playbook the same.
That's helpful in allowing more people
to actually be able to get their arms around it.
Definitely, but we won't say standard market design
because I'm sure there are people who are still haunted
by that from the early 2000s.
Yeah, I've only been here since 2020,
so forgive any ignorance or things I'm stepping on
that are sensitive topics.
We at a high level have talked about the challenges
to interconnection.
I'm sure lots of people have lots of opinions or you know that the document and their concurrences or otherwise to improve interconnection.
So, I think.
Can you provide a summary of like what actually is being improved in 2023.
I can do my best. And I know Pam said that there would be some sources that are shared.
I know there are a couple of law firms who've done a really good job of this. I think Rocky
Mountain Institute has done a couple of good, has done a very good job of this. And as we've
all talked about, the commissioner statements can highlight some of the main changes. But
for me, I can organize these into a few categories. One is that the overarching theme is that order
number 2023 requires certain new procedures to improve the efficiency of interconnection.
efficiency is the main focus. And there are a few different ways that the order goes about that.
One is by requiring the use of a first-ready, first-serve process. What that means is there's
no holding your place in line indefinitely, and you can't sit in the queue if you're not
ready to move forward with conducting some of the further studies and eventually moving to the stage
of interconnection. And we call that commercial readiness, and that can be demonstrated a number
different ways, not only by signing certain agreements but by putting up deposits as
collateral. And commercial readiness is a real focus of order number 2023.
And then the second part of that efficiency and using the first ready first serve process is that
order number 2023 requires that all transmission providers use cluster studies. What that
means is that groups of generators are studied together, not one by one, and the cost of
upgrading the transmission system to accommodate their interconnection are shared among the
different generators in the group and the cost allocation of those upgrades can vary.
It's been a real subject of debate and Order 2023 offers really detailed guidance on that
cost allocation.
But I think at a high level what's important to know is that the costs are shared and it
removes some of the uncertainty that we focused on about whether you're going to be lucky
and get a low cost upgrade or be unlucky and get a high cost upgrade.
And then I'd say the third major overarching part of improving efficiency is on the transition
provider side.
It's that order number 2023 establishes binding deadlines
and pretty substantial financial penalties
for transmission providers who may not,
if they don't meet the deadlines that are in the order.
And that's for a few different reasons.
One is just simply to encourage their staffing up, right?
A number of transmission providers,
I will say they have a lot on their plates right now.
They're trying to do a lot to manage their changing systems
while operating the system on a second by second basis,
right? They have a really heavy lift. But the lack of finding deadlines or substantial penalties
may have led to transmission providers not prioritizing completing these Q studies on time
and getting answers back to interconnecting generators. And so one focus of the order is
to essentially raise the stakes and to make sure that transmission providers are allocating all
of the resources that they need to, or hiring new people if they don't have enough currently
to make sure that they can get through all of the studies that they're required to do
by the deadlines that the order requires. No, that makes sense to me. If I could ask a
quick question on that. Yeah.
The penalties, not all transition providers are the same. If I understand it correctly,
like ISOs and RTOs are one example of a transmission provider, but then there's also,
I would say, utilities and restructured or regulated markets. Do you think the penalties
are still, and it's okay if you don't have a fair answer for this, but are the penalties
like interesting and enticing enough for like both cohorts of transmission providers there?
Do you think like one being a nonprofit and one being, you know, like an IOU, they kind
of have different pocketbooks and different senses of what's important for them financially?
That's a really interesting question. The penalties are pretty substantial. And so,
as you mentioned, there are some large transmission providers and some smaller transmission providers.
And this is where I don't remember exactly right, whether they're the same or not,
but I think they're uniform penalties. It's a certain number of dollar amount per day of delay.
But essentially, they do have different pockets, and they also do have different cost structures.
And so this is something that Commissioner Christie actually highlighted in his concurrence,
that RTOs and ISOs, which are nonprofit organizations that are funded by their
stakeholders, their customers, may not have the same incentive to feed their processes
based on these financial penalties, in theory, they could pay pretty hefty financial penalties
and just pass those costs on to their transmission customers.
And that in and of itself is a cost shift, right, from the interconnecting generators
who need the studies to transmission customers who may not be making any changes at all.
And so that's something to keep in mind, too, and it's kind of a broader theme of what to
consider moving forward.
Are there ways that beyond order number 2023, the cost allocation between interconnecting
generators and transmission providers and then those transmission providers
customers can be modified so that the people who are benefiting from the
studies are paying, or in the case of transmission providers who are behind
the eight ball, the people who are causing the delays are actually
penalized in a meaningful way.
The transmission providers though, um, that are in non restructured areas.
Could, could they still rate base?
I don't know.
I mean, the penalties wouldn't be rate-basable, just like a five-bar, the penalties can't
be rate-basable because it's not an investment or an asset of the utility, if anything, it
would be an O&M, so it would be in that O part of the rate case, and that's usually
a fixed negotiated amount that's an estimate, right?
And so if they're delayed a number of years, they could then assume that they'll continue
to be delayed to the same extent in the future, and they can ask for an amount of that money
in their next rate case as part of their overall revenue requirements. But I wouldn't be surprised
if it came down to study delays if a state PUC would force them to allocate some of those costs
to their shareholders instead, not give them the full amount in their revenue requirements. But I
think all of that gets a lot more into state retail rate making, and I can't give you a
solid answer on it. No, I was just going to say,
that's a very interesting question, I think. The cost allocation issues are the ones that
I'm most interested in, because I think it's really tricky to figure out how you can get
a nonprofit or someone who passes through these costs, who actually have a meaningful
reason to change their procedures. And I think that deadlines are part of it, that theoretically
if a transmission provider was just consistently failing to meet deadlines, they would be noncompliant
with a FERC order. That could be the subject of an enforcement action, and that could carry
its own penalties. But I would be shocked if the commission really wanted to pursue that.
Obviously, I have no personal insight into it, but I'm curious, beyond the financial penalties,
which the transmission provider may or may not pay itself, I don't really know what else you do
to try to encourage them to speed up these studies. And I do want to recognize, again,
as I said earlier, they have a lot going on. Interconnection is a big piece of their work,
but it's not everything. They're operating real-time energy markets. They're balancing
on a second basis the frequency of the grid. I mean, they have a lot going on. And so, I think
One, one challenge and one reason they've been cut a lot of slack in the past is that they are the experts on managing and operating their own system, but it did get to a certain point with the queue delays and a lot of the backlog, but I think the commission decided that needed to step up and that even though transmission providers.
Maybe do a thing they were doing the best they could that the imposition of some more standardized procedures and deadlines could encourage them to move things along.
One quick question on commercial readiness, and this is just me not having a very strong background in project development.
So maybe this technically should have gone in the first part, but when we talk about whether a project is ready,
is that on a scale of intent to make a project to a wind turbine exists and is on the ground or what are they expecting?
Well, when I say commercial readiness, and I think this is a good thing to clarify, I'm really talking about financial readiness, right?
I definitely will not get into the engineering of what it takes to build a wind turbine or
200 wind turbines.
But I can say that what Order 2023 sets out in terms of commercial readiness is what type
of financial deposit and other showings, whether it's site control or necessary permits or
approvals from your state commission, what boxes do you need to check before you can
move to the next stage of the interconnection process?
And that's what FERC is setting out some standards for.
And so that might not, that might be a certain percentage of site control, I think order 2023 has that you have to have 90% site control before you can move to the cluster study process.
And then separately that you need to post certain financial collateral to show that you are not just invested but then you have some skin in the game, and some of those deposits are are forfeitable, if you pull out of the queue and as you get later
into the interconnection process, a larger portion is forfeited.
And so all of these checks are supposed to work together to make sure that the
interconnecting generators are serious about planning to achieve commercial
operations, that they're not taking speculative queue positions and beyond
their intentions, that they actually have the money to back this up, that these
are serious projects that are going to be added to the system and therefore are
worth the transition providers taking the time to include them in the cluster
studies and to allocate them costs.
Yeah.
for me, if people are really curious about the details, because no doubt there's a lot of details,
both in the summaries, and then if you really get crazy, look at the order. They do have some very
specific and tangible commercial readiness requirements, which people can kind of look
at to get a better feel for it. Definitely. That's a great reminder.
What we've heard is that some people have already implemented some of these actions,
some people being some transmission providers, I guess is the right word to say.
And so I guess, Cece, if you could just like speak to that, and then like, yeah, I guess
just starting there, like, you know, some people have done this, but we're really raising
the floor here.
Right?
Absolutely.
So I can just give a brief overview.
I know that I did some quick digging and found out that KISO, MISO, NISO, and PJM had already
submitted proposals.
And in some cases, we're already using a cluster study process.
So, that represents California, the Midwestern part of the US, New York State, and the Mid-Atlantic
out to Chicago for those people who are listening who may not be as familiar with those regions.
And I think one thing that's worth pointing out is that BERC, as you said, tends to raise
the floors, right?
This is not an untested process.
Cluster studies is something that has been done before, that other RTOs and ISOs have
done successfully for a number of years in some cases, and ISO has had a classier process
for a long time.
And I think that's one reason that the commission may feel confident taking such definitive
action is that they're not requiring something untested.
This is a process that not only has been in place and used successfully by certain regions
of the country, but has also been shown, at least in those regions, to contribute to relieving
some of the interconnection queue backlog.
So I think one way I like to think about it is that FERC is likely never going to be the
first mover in an area.
And that's for good reason.
I mean, if FERC came out and required transmission providers to do something that was untested and
maybe wasn't feasible in the end, then that might set back energy policy and, in this case,
interconnection queue reforms a number of years. But I think by waiting to see what works in
certain parts of the country, and then, as we've talked about, grazing the floor,
making sure that once something's been shown to work, that every part of the country can
implement that and can use it to more efficiently process their interconnection request,
I think that's really one of the benefits of having a federal regulator is to be able
to provide that consistency and whether the transmission providers want it or not to spread
some of those best practices across the country.
One question I had related to this to pull on this as a little bit more, would it be
fair to say that this practice of kind of seeing what works in different pockets of
the country, like maybe at the state level, maybe at the market level, and then using
that given that it works like federally is something that has been done before or is done
often? Yeah I don't want to get too far ahead of myself here but I think there are some recent
examples that we can really look to. So I think order number 841 was a really good example. There
had been regions of the country where energy storage was being deployed and deployed effectively
but was running into certain barriers where energy storage resources weren't getting compensated for
the full range of services that they were technically capable of providing.
And there were some regions that were starting to experiment and were calling energy storage
negative generation, or were trying to figure out how to solve some of these problems of getting
these energy storage resources paid for the electrons that they're putting onto the grid.
And I think FERC served kind of a dual role when thinking about energy storage. One was a
convening authority that the commission organized a series of technical conferences that brought
people together from different regions of the country to talk about what was working
for them or areas for future improvement.
And then the commission used its rulemaking authority to direct certain regions to comply.
And I think one thing that we saw in the energy storage context at least was a little bit
more flexibility than we see when we're thinking about interconnection.
And part of that comes from having a new technology.
I mean what 841 required was that energy storage resources be able to participate and
And what that means for transmission providers, and in this case it was for independent system
operators and regional transmission organizations only, was that they develop a participation
model.
But that participation model was really more guideline-based than prescriptive, and the
commission left a lot of the details to the compliance process.
And so I think that was one example, a little different than interconnection, kind of along
the same lines.
order number 2022 took a similar approach when it talks about requiring transmission – excuse me,
independent system operators and regional transmission organizations, again, to develop
a participation model for aggregations of distributed energy resources. It was the
same sort of requiring a structure but leaving the implementation details to a case-by-case basis.
And I think you can see shades of that in 2023 with interconnection.
And interconnection we know a little bit more about, where the order is a little more prescriptive
because there are these procedures like first ready, first ready for cert processes and
cluster studies that have been broadly successful across the country.
But there is still some room for flexibility.
And this is something I wanted to mention earlier, which is that the ISOs and RTOs,
in complying with order number 2023, still can take advantage of what's called an independent
entity variation.
What that means is that there is some level of deference given to the fact that these
RTOs and ISOs are independent organizations that operate their grids and have some level
of expertise and also facility with the interconnection process themselves.
And if there are things that work in certain parts of the country for one reason or another
that may not work everywhere, the ISOs and RTOs are free to propose and explain to folks
why their alternative is actually comparable.
This is something that can get a little confusing,
so maybe it's worth touching on here.
The ISOs and RTOs have one standard,
independent entity variation,
where as long as their proposed option is comparable
or equal to what the order requires,
it may get approved by FERC.
If you are outside of an ISO or RTO region
and you're a transmission provider
or in that other non-restructured part of the country,
you do have a higher standard.
Maybe last thing I just wanna like say on this section,
and then maybe we can move on.
I just think this is very cool to see that things
that work in kind of smaller geographies
can get adopted as like good models.
And so if anyone says like,
why should I really like get active in my local community
and like get a new legislation passed just for my city
or just for my state or something like that,
I think the point is, if you can prove that it works, then it's a model that kind of
maybe the state can adopt or it could even get adopted at the wholesale market or the
federal level.
And so I think personally, one, help your community because it's good for your community
and it's the right thing to do, but these things can be proof points that can eventually
get adopted at broader scale, which I think is really cool to see.
Yeah.
I would just add that.
I would just add that, you know, this is where urban planners, this is where we get our best practices from, like, from real things that real communities do.
So this podcast is called InDERmediate, with the DER being distributed energy resources. So what are some ways that you think that this order will impact DERs?
Yeah, that's a great question. When I looked back at order number 2023 before this podcast,
I realized that most of the reforms, or at least many of the reforms, are focused on
the interconnection of large generators. But order 2023 does direct transmission providers
to modify their small generator interconnection procedures. So those are the procedures used
by generators that are less than 20 megawatts in capacity. And that those modifications
should allow for consideration of alternative transmission technologies and some other discrete
changes. Order number 2023 also requires transmission providers to maintain a publicly
available heat map of available transmission capacity. And this is something that I think
system modelers at least are getting pretty excited about. I'm not a system modeler. I'm
also somewhat excited about this because even though some people who've criticized the order
have said that this is a pretty heavy lift for transmission providers, that they have
enough to do. They shouldn't have to build and maintain these heat maps. This is really
kind of a key for distributed energy resource developers, because these heat maps are
essentially treasure maps to show which parts of the grid are underutilized. And if you're – if
you have a low budget, especially because you've got a small resource or a number of small
resources, if you have a heat map that's being updated, if not in real time, at least relatively
recently, that can show you where there's headroom on the system, well, that's really a key to
unlock some easy, low-cost interconnection. And small generators typically have their
own interconnection procedures that are dependent on the distribution utility and their systems,
but I think the heat map could be a really powerful tool if you're developing distributed
energy resources in figuring out where you should locate those resources, not only to make sure they
can get hooked up to the system, but also to give them a chance at making money, at relieving
congestion, and at being in a location of the grid where they're really providing value to the
system. Yeah, I'm also very excited about the heat maps. I
didn't see that. I'm curious to see what that looks like.
Go heat map. I'm so excited for the heat map too. I'm sure
energy Twitter will be very excited as well to have more
things to screenshot.
Oh my gosh, I hope energy Twitter survives for the era of
the heat map. Energy X.
I'm assuming it'll be like the, the heat maps with prices. I
hope it is.
Lulumastodon Skythread.
And then without saying like specific names,
just to be neutral,
I know there's some startups that are like
kind of working on heat map type products as well
for like project developers
and people developing projects to use,
which I also think is really cool and I love that.
That's great.
Folks can name names in the comments.
I'd love to see those.
So we love heat maps.
I think we could talk about them for a while.
Do you think that's like the main takeaway for DERs?
or do you think there's other like key areas?
You know, I'm not really sure.
I think honestly,
and this is something we'll start to talk about
just in the last part of the episode.
I think one thing that I wanna emphasize
is this process is just beginning.
We can talk specific dates and compliance,
but one thing that I saw from following
the compliance process for orders 841 for storage
and 845, which was the last round
of interconnection procedures,
is that there are some questions
that transmission providers haven't figured out yet,
and even FERC may not have figured out yet.
and only when those issues are raised by transmission providers to attempt to comply
or by stakeholders whose projects that are under development are affected will we start to iron
out some of the details. So I think maybe I'll put a pin in that for implementation details. I think
we'll start to see pretty soon what parts of this final rule DER aggregators are interested in
debating and whether some of those proposals make it into FERC orders in the form of compliance
orders on compliance filing.
Yeah.
And I think to touch on that, cause this maybe is intuitive, but like, isn't
totally obvious unless you think about it for a second here.
Um, and we are like, so an order gets issued, right.
Or whatever process, like whatever step in the process we are today.
Like, could you raise that up one level and just let people understand
like the full process from, or like the life cycle of a fork order or like
whatever the right way is to say that.
Oh man.
Yeah, I'll do, I'll do two parts.
So I think it makes sense maybe to start with going backwards.
The way that a rulemaking is initiated is typically by a notice of inquiry, an NOI,
and that can be a number of years before the final rule gets issued.
And after the notice of inquiry, the commission takes comments in many cases and will start to
scope out the range of problems that it may want to address in a single rulemaking.
And the next step is to issue either a notice of proposed rulemaking, a NOPR, or in some
cases for really big rules, there'll be even a step before that, an advanced notice of
proposed rulemaking, an ANOPR.
And through either the ANOPR, NOPR process or the straight NOPR process, the commission
will set out the range of possible issues that will be addressed in the final rule.
And that's a somewhat binding range.
There are legal reasons for that, but essentially the stakeholder community needs to be put on
notice that these are the things that the commission is considering changing, and if
you have comments to submit on this range of issues, submit them now.
And typically, because that NOPR has to be almost entirely inclusive, the only changes
from the NOPR to the final rule stage tend to be determining which issues not to take
up yet.
Because, again, you can't put in a new issue in a final rule without notice, without adequate
notice of the stakeholder community and an opportunity to comment on those changes.
And so the progression from the NOPR to the final rule will essentially just be a removal
of certain issues that the commission has decided based on stakeholder comments are
either not right for consideration or the commission needs to gather more information
before they're ready to move forward.
And then you get to the stage just before where we are now, which is the issuance of
the final rule, which happened over the summer.
And that's when the final requirements are written down and the commission explains that
the requirements will go into effect at a certain date in the future, and that all of those
implicated, in this case transmission providers across the country, will need to submit compliance
filings to show either that they're already in compliance with the rules or that they're
making changes to comply with the rules and laying out what those changes are. And so that's
really where we are right now. For compliance, the rule was published in the Federal Register
in September, and it becomes effective in early November, which is just a bit of a quirk of
official effective date. But we're really well on the way towards these rules being translated from
prescriptions to actual policies and procedures. Because compliance filings are due starting in
February 2024. And the commission has signaled that it's interested in moving quickly through
this process. Often final rules will give longer opportunities for compliance, maybe 120 or 180
days. But order number 2023 provided 90 days. And that is a pretty strong signal to transmission
providers that commission serious about changing these timelines and improving efficiency immediately.
So that'll be interesting. I mean, complying with large final rules like order number 2023
often takes multiple rounds of compliance. That means that transmission providers will be submitting
proposed tariff changes and FERC will be reviewing those changes and then telling them where yes,
you've achieved compliance or no, you're not there yet. And that's going to be an iterative process
over the next couple of years. So I think it's just helpful to get a sense in terms of timing,
how long this can all take. I don't remember exactly for order number 2023, but often this
can be a process of three to five years total, from scoping the notice of proposed rulemaking,
trimming the issues into a final rule, issuing the final rule, and then processing several rounds
of compliance. I think that compliance for order number 845 only wrapped up a year or two ago,
so that was issued in 2018. It may have taken three years to get through to the point where
every transmission provider with compliance.
And I think we could probably expect
something similar for 2023.
Yeah, going off that, I'll also add that
regarding DER aggregations, you know,
just because order 2222 became final and passed and whatnot,
they're still going through compliance for that.
Yeah, that's a great point.
Just because, you know, you can have DER aggregations now
doesn't mean that everyone's complied.
We don't necessarily know how they will comply.
and so therefore we don't necessarily know how that will interact with this order.
Great point. This is where we bring up toasters again. Just because everyone's working on
compliance doesn't mean your toaster can participate in the grid. Exactly.
We love toast. So I guess we're certainly making progress here with order 2023, but
can we sort of get a feel for like what's next and maybe what the key open areas are that might
be kind of improved upon from here are. Yeah, definitely. I think this is one of
the most interesting areas for discussion. So, when we think about interconnection procedures
and what needs to happen to continue to facilitate more efficient interconnection,
I think one thing that's really important is to remember that interconnection and transmission
planning are really interrelated. And you can look to some of the Commissioner's separate
statements for hints at next steps beyond the scope of Order 2023. And a couple of those issues
really do focus on this transmission interconnection interface. So one thing that order number
2023 did is that it's declined to require any additional integrated transmission planning
or to require reforms to how transmission providers allocate the cost of new transmission.
But this issue of transmission planning and especially, you know, more thorough transmission
planning is something that both Commissioner Clements and Commissioner Christie flagged
in their concurrences. And one other issue that's related is inter-regional transmission
development. It's been something that FERC has talked about, at least individual commissioners
have talked about over the last couple of years. And I think those who work in academia,
those who post on Energy Twitter have talked about inter-regional transmission planning
and development as kind of this holy grail, whether it's the macro grid that you see or
whether it's just making more efficient processes to consider transmission lines or transmission
upgrades that can benefit more than one system. That's an area that is outside of the scope of
this order and probably still a focus for the commission,
but something that because it's by its nature inter-regional,
I think we'll have to be a more collaborative solution
rather than maybe something so top-down.
But there are also a couple of issues that I found
really interesting from the commissioner's concurrences.
One of them was that Order 2023 declined to
change the funding requirements for upgrades on affected systems.
Affected systems are transmission providers,
but we can think of them as the unlucky third parties here who get affected.
So, for example, if you have a new power plant that's trying to interconnect in Virginia,
but it interconnects in southern Virginia, the transmission provider could be Dominion
and the interconnecting generator could be trying to participate in the PJM market.
But because of the physical topology of the transmission in that area, there may be electrons
from this new generator in Virginia that actually will affect the system in North Carolina operated
by a neighboring transmission provider. And so that North Carolinian utility that owns its own
transmission system may also need to build upgrades to facilitate the interconnection of
a generator nearby, and that's an affected system. And there are different rules for
different parts of the country right now that govern both what affected systems have to do,
whether they have to do those actions by any sort of date certain, and then how those upgrades,
if they build them get paid for whether it's passed along to the interconnection customer,
whether it's refunded by the neighboring region. That's an area that Commissioner Christie
highlighted as being a potential area for further inquiry and maybe for the rulemaking and that's
something that I would love to see and especially love to learn more about. And then kind of along
the same lines about you know shifting costs and who pays, again both Commissioner Christie
and Commissioner Clements, but especially Commissioner Christie, emphasized that Order
Number 2023 declined to address certain other cost allocation issues. Again, this challenge,
perennial challenge of who pays and is it the person who caused the cost versus the person
who benefits from the infrastructure? That's something that I think will keep energy regulators
busy for a very long time. Cool. Cece, thank you so much for joining us. This has been awesome for
me, especially as someone not as familiar with policy and FERC and regulatory things
like this.
I feel like you allowed me and Pam has always allowed me to engage, even though I'm outside
of my comfort zone and I've learned a ton and I hope other people did, so thank you
so much for coming on.
Absolutely.
Thank you both for having me.
It's always great to talk interconnection and I think outside of our comfort zones is
something we can all have in common, right?
These are pretty weedy rules and I think unless you're an interconnection engineer, it's going
be hard to know exactly what all of it means, but it's great to talk about it and to try to
try to wade through some of that together. Thanks for listening to this installation of
the InDERmediate Podcast with CC Coffee and our hosts James Gordey and Pamela Wildstein.
I'm Ben Hilborn and you can find us anywhere you'd like to download your podcasts such as Spotify
or Apple Podcasts. You can also find us on the web at InDERmediate.com.
If you have any questions or comments about this episode, feel free to email us at InDERmediate
at gmail dot com.
See you on the next one.
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