Asked by NM RETA on July 27, 2022. View meeting information here.

Initial Response: PNM

We can certainly take that [question] back. It's not something that we have done in the past. We can certainly take that back and see if it's something that we can go ahead and include in a presentation going forward. That does remind me there was a previous question about presenting historic peak information. We do have a filing we make every year--it's our Case 3137 filing. It shows a load and resource balance, including a forecast for peak each year. So, we will post a summary of that.

We would note that there are differences in the way resources are accounted for as well as the contributions of different resources over time, as folks have probably gathered from previous presentations on ELCC [Effective Load Carrying Capability] that resources will change as a function of both system conditions and the penetration level of given resources on the system, as well. In the last IRP we move from installed capacity accounting for thermal resources to force capacity accounting. So, you'll see some differences in the way the numbers are represented. Take that into account.

You can also go to the [Public Regulation] Commission's website to search for the Case 3137 and pull out those filings we make each year to take a look at what the loads and resources tables are showing.

PNM Update:

Asked by WRA on July 6, 2022. View meeting information here.

Response: PNM

This is something that we'll dive into much more detail in a future meeting--probably along the lines of grid modernization (grid mod) and distributed resources. It's both. As we move the system forward, if we want to get to the fully decarbonized system, unleash the power of our customers, and make sure we're doing everything we can to move this forward, there's going to have to be incentives for behind the meter, customer-owned storage.

Having those incentives right and having those hooked into a distributed energy resource management system, so that the utility operators are actually the ones who can control that storage to some degree is important because the more we align the operation of behind the meter resources with the system requirements--and not individual customer requirements--the more those resources can offset the larger utility scale transmission side and resources.

We're also going to need to have utility-owned distributed source storage on our side of the meter at different places, depending on the location and the customers. There may be advantages to the utility owning and having it on its side of the meter versus on the customer side. It may be both. There is also going to have to be utility scale storage; you're going to have to have it in the load pocket; and you're going to have to have it out near resources.

We envision this as using storage as the way to manage the dispatch of the system to manage reliability and to manage the efficient use of the transmission and distribution system. There's going to be so much storage on there and so many different components of it, that it's all going to have to be worked into computer algorithms--using AI and other things to make sure that we're able to manage this all--in real time.

We don't think you want to count out any of those options. We need them all in order to make sure that we can manage the system reliably and cost effectively and move the decarbonization path forward. We can't eliminate any of our options right now.

Asked by NMPRC on July 6, 2022. View meeting information here.

Response: PNM

Yes, if everything could be interconnected, efficiently, and if we can alleviate the constraints. Our PNM subject matter experts who developed the forecast will do a presentation on it.

If there are things that need to be done to the interconnection process that can be overcome, we will need smart meters--as more and more of distributed resources are added, we will have to have a view into the edge of the system right up into the customer points. With smart meters with AMI we will be able to manage renewable production and customer usage by each individual meter.

In order to make sure that our operators are able to manage the system effectively, they can't be blind to what's going on behind the customer meter. They have to be able to see that, especially, if this adoption rate is what we see materialize, it would represent approximately 1250 megawatts.

Right now, we're a 2000-megawatt system, and if we have approximately half of the resources of the system behind the meter our operators will have to have visibility in real time to make sure they can operate the system.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Response: PNM

We can certainly take that feedback and try to organize it into a write up in the IRP itself. It shouldn't be too tough to do.

Typically, the more detailed discussion of the weather data and the load forecast development is in the Buildings Appendix C of the 2020 IRP.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Response: PNM

The demands are much lower, but it doesn't alleviate the demand that's needed right after sunset. You can't just consider a very short window; you need to think about the overall system dynamics: The utility has to have enough resources under its control to meet its net peak, including reserves. But then, at some point, it's not just about that net peak and the capacity associated with that. It also becomes the amount of stored energy and the amount of energy that you need to be able to carry forward overnight into the hours of the morning to be able to sustain meeting your loads.

We are going to present another reliability analysis, looking at what the risk hours are and showing what that is as it changes over the time frame of the study--2023 through 2042.

When we presented the (preliminary) ELCC [Effective Load Carrying Capacity] analysis, we talked about doing an ELCC analysis not just at a static point in time, but at a couple of different points in time throughout our forecast horizon, showing, that as the risk hours change, the effective load carrying capability of a given resource to meet those risk hours will change.

So, the amount of resources we're going to have to add over time is going to increase because the solar, the wind, and the storage are going to be adding less and less ELCC as their levels of penetration increase throughout the period of decarbonization.

Furthermore, you're going to have to deal with not just that net peak, but also the flattening of the net load as it wraps around into the early morning hours.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Response: PNM

Yes. And whether it's behind the meter solar or utility solar or utility scale solar, the more of it that we add, the more it's going to depress consumption that is not served by solar in the middle of the day. But the requirements that we have to serve when the sun starts to set are going to remain at those higher levels. We're going to have to have resources to cover that, depending on what else is added to the system, because you can't think about it as just solar, as you start to add more storage.

In the 2020 IRP Appendix M, there are some heat maps of the loss of load risk hours: As you go further down the decarbonization path, as you add more solar and then add more storage, the storage has the tendency to flatten out that peak, but you can only operate for a limited duration.

The solar will push the capacity needs into the early evening period. And then, as you add more storage, it's going to further shift that risk later into the evening overnight, eventually into the early hours of the morning.

So, you can't just think about it as this really short window in the near term. If we only had solar, it's going to be this near-term short window, but as we go further and further down the road, you're going to start to see that loss of load risk. And you can see this even in the presentation that E3 did on its Southwest study: The overall loss of load risk for the southwestern region by the time you get to 2030-2033, if all the utility IRPs are followed, you start to see that loss of load risk start to creep into overnight and early mornings because of the duration and limitations on energy storage.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Initial Response: PNM

[Perhaps we can continue this discussion offline to clarify how you're thinking about this presentation's use of weather variables in the development of the PNM retail load forecast.] This does not concern neighbors, or what our availability to purchase power from them is.

Asked by New Mexico State University on July 6, 2022. View meeting information here.

Update: PNM

The PNM modeling framework and Phase 1 modeling scenarios were discussed during the February 15, 2023 meeting.

The framework for modeling run requests was discussed during the March 15, 2023 meeting.

Asked by a member of the public on July 6, 2022. View meeting information here.

Initial Response: PNM

We'll have to have one of our rate design folks address this as well.

Initial Response: Itron

It's pretty complicated, right? Behind the meter and community solar is behind the substation anyway. We're not saying it doesn't necessarily change how much energy people are using, but it changes how much the utilities deliver. And, so, as it reduces the amount that utilities deliver, it reduces the amount of revenue they recover--if it's a volume based charge, not so much if it's a demand charge.

That means for residential, where you still have sort of a volume base charge, you're recovering less of your fixed costs, because you're delivering less energy, and, therefore, you're going to have to raise the prices to recover the revenue to cover those fixed costs.

So yes, there's definitely a relationship there and we are sure the rate people are working on that to find ways to make the system work financially.

PNM continued.

We'll have our rate group talk about that a bit as well. I would suspect that if there was a change in the way net metering rate works for residential, for example, you would see a reduction in the amount of folks that are trying to put behind the meter solar residentially. Because of the size of the credit paid to those customers would change.

We do think you will have to look at that if you want to properly incentivize behind the meter storage or distributed storage. Right now, our block rate is 8am-8pm. That period is too long, and the net energy metering rates potentially too high, to incentivize someone to add storage as well.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Initial Response: Itron

If you look down below, probably about right now, a quarter, maybe 30%, of the generation is nonresidential.

There's quite a bit in the water customers--water utilities that generate some of their own power. There's some in small commercial and general power categories. And then some of the really big customers actually have their own solar farms, but those are not behind the meter: Their solar farms are located near the transmission system somewhere and are putting the energy directly into the transmission system.

So, the really big non-residential solar generation often is not behind the meter, but there are entities like hospitals and some schools with parking lots covered with solar.

Asked by NM RETA on July 6, 2022. View meeting information here.

Initial Response: PNM

We'll have one of our internal subject matter experts come in and talk about some of the specific drivers behind that. We'll make sure to keep that on the agenda for a Load Forecasting meeting in November.

Update: PNM

Topics related to this questions were discussed at the Load Forecasting meeting on December 15, 2022.

Asked by NM RETA on July 6, 2022. View meeting information here.

Initial Response: Itron

That's a monthly cycle throughout the year.

If you put in twice as much generation, everything is twice as big. And so, the minimum is twice as big, the maximum is twice as big, and the range is twice as big. If you have twice as much solar, it's going to double the maximum generation; it's also going to double the minimum generation.

So, the gain is twice as big during the year, going from winter to summer. The winter generation is low because the days are short. The summer, the generation is high because the days are long. The biggest generation is usually in April or May, so that might show up in the June bills. As it gets hotter and hotter, the generation becomes less efficient--more light, but less efficient.

Asked by New Mexico State University on July 6, 2022. View meeting information here.

Initial Response: Itron

I've seen some national lab studies, but I don't know right off the top of my head.

Initial Response: PNM

We can try to pull together some of that trend information but our focus in this IRP is about PNM's service territories. We're making our focus our weather and our load forecasts. PJM is outside the context of PNM's resource plan.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

See PNM’s response to this question in IRP Report, July 6, 2022.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Initial Response: Itron

That's not a bad idea. It's certainly something that we could take a look at to see if anything's changed significantly relative to 2015-2018.

This is just doing the weights. Those weights are something that could be updated. We will look at whether we're going to do that or not.

PNM asked question.

Could you provide a little bit of additional context in terms of how the weights, or the weather variables are done? You're coming up with a weighted average weather variable that represents the PNM system, so what this would be really getting to is, has the load growth in the system proportionally changed such that the weighted variable for weather would then change because of that?

Itron continued.

If you look at the weights, like Albuquerque, on the cooling as 77.8% weight, that was based on that 2015-2018 billing data. So, it might be a little different--bigger, smaller, probably a little bit bigger.

Asked by Brubaker & Associates on July 6, 2022. View meeting information here.

Initial Response: Itron

This change is driven mainly by the high level of activity in the last couple of years. As a result, the new solar capacity values (red line) start diverging from the old values (blue line) before the forecast begins. The higher level of historical additions put the forecast on a different and higher path.

We’re not sure of what all the logic is that goes into that in terms of government, attitudes towards solar, and government money and so forth. So, there are a lot of things that go into it, we’re sure.

Asked by Brubaker & Associates on July 6, 2022. View meeting information here.

Initial Response: PNM

That forecast, at least the near-term piece, was developed by PNM’s internal customer programs and customer behind the meter internal department. We can have them answer the question; we've already got a meeting set up.

In 2020 or 2021, we might have underestimated the amount of rooftop additions that year by 50%, so there's just a very, very strong uptick in the amount of customers who are trying to add behind the meter solar—there’s a lot of folks in the queue.

This was raised at our kickoff meeting—there’s some reworking the interconnection manual that will hopefully make it easier for folks to interconnect. All of those things are going into the change in the forecast from the behind the meter perspective.

Brubaker & Associates continued.

So, then I guess, what you're saying is that Itron received an input for the capacity growth that came from PNM?

PNM continued.
Yes.

Brubaker & Associates continued.

It would be great considering how much change is going in this versus 2020, We'll cover that in a future session. We have a further explanation of when there was shortfall. Let's understand how the projection over the time was developed.

PNM continued.

We can add that to our list.

In a future meeting September/October, one of our representatives from our customer account groups--who's really in charge of doing the behind the meter forecasting and oversees a lot of the customer requests and their connections--can talk about the uptake that they've been seeing, and the sheer demand for interconnection of behind the meter assets.

Asked by PNM on July 6, 2022. View meeting information here.

Initial Response: Itron
The most interesting work is done by PJM, the transmission system operator up in the Northeast. They take each 30 years, but they take each of the last 30 years, of actual hourly weather data, and run it through. They've got an immense service territory. It could be cool in Chicago and boiling in Virginia, so coincidence is a real issue for them in terms of their overall system load.

Their way to deal with that is just to take the actual year of historical weather data for all the stations, and run them through the models, a model of what's going to happen next year, or in 10 years--run 1995 through, run 1996 through, run 1997 through--and when those patterns go through, you've got a different load forecast for that future year. You can post process those forecasts. They were doing that with daily models of zone peaks, and now they're looking at moving to doing hourly modeling.

So, that's the most detailed approach to understand the range of outcomes that you can get today, or in 10 years, with those various weather patterns.

That doesn't deal with the trend issue but the range that you can get today. Given that, just looking at the past history, that range includes anywhere a trend could take us in terms of the middle point. The middle point is moving slowly; the range around that is big at any point in time.

Understand that range is the key. The one scenario that Itron would do is going extreme--Let's find the most extreme weather and do an extreme weather run, an extreme year.

We're pretty focused on a summer peak for PNM, at least now, but an extreme year would be a year with a cold winter and a hot summer. Or maybe it's part of two years that accomplishes that.

Asked by Brubaker & Associates on July 6, 2022. View meeting information here.

Initial Response: Itron

Yes. The actual observations are from NOAA. They usually make them about 10 minutes before the hour. And so, the number that you're getting for an hour, say, from noon to one clock, might come about 1250. So, it's highly synced in that sense.

The challenge is doing the forecast to keep that synchronization in place, so we do pick one weather pattern for all the forecast years, and just map the hottest day, the second hottest day, third hottest day, fourth hottest day, to that consistent pattern through time?

The global horizontal radiation data that goes with the hottest day is from what that looks like on the typical hottest days each month.

We've gone to painful efforts to keep that analysis going. It's not easy but it's something you want to do.

Asked by a Member of the Public on July 27, 2022. View meeting information here.

Response: PNM

This question relates to the load forecast discussion we're considering. From the IRP perspective, we don't model the distribution system; we're modeling the bulk electric system. If there are distributed energy resources--let's just use behind the meter PV, for example--we do have an explicit behind the meter PV forecast that is developed in the process of developing our load forecast.

One of the things that we're thinking about doing that we don't have right now is, if we were to say, install a distributed energy resource management system, as well as have AMI [Advanced Metering Infrastructure], and the necessary grid edge technologies, which would give us visibility into the edges of the system. For example, right now, we can't see, specifically in real time, what individual customers have in terms of behind the meter generation, what's being consumed by their loads, and what's being delivered back to the grid. That's because we don't have AMI and other technologies on the system.

If we can get those systems in place, then we can have a better representation of your customer sign up and a better control of, say, behind the meter storage resources. One of the things that we'd be looking at is: What's the total volume or total penetration level of behind the meter PV that's on the system, and then, what's the total amount of behind the meter storage on the system that would be potentially coupled with some or all of that behind the meter PV?

If we had a DERM (distributed energy resource management) system that gave us control over that, rather than just having the net effects of those behind the meter resources reflected in our than net load, we might move those to being modeled as dispatchable resources, where, based on the system conditions, we would see the charging the system, charging and discharging those batteries, potentially accepting or turning down the export settings on inverters, depending on what system conditions best optimize the use of that behind the meter storage.

But, if that would be done, we would be taking an aggregate of all of those individual resources and aggregating them up to a bulk representation of those distributed resources. This gets into the same thing that the modeling presentation is alluding to in terms of the detail of the model performance: We don't have the computational power to do a combined, complete representation of the distribution system and each of those resources on a 20-year hourly basis to do overall system capacity expansion.

So, we need to work towards that. We're going to have to push our vendors in terms of the way they're developing these models. We're going to have to continue to keep an eye on computational power--what new forms of computing might be out there.

But in terms of the way we would have to look at distributed resources, we'll have to look at how we can aggregate those up to the bulk level, and what devices we have on the system that would enable us to have better visibility, control, and dispatch of those resources if we do aggregate them up to the bulk level.

Asked by New Mexico State University on July 6, 2022. View meeting information here.

Initial Response: PNM

We understand the question as asking if we could somehow work into the forecast an increase in the frequency and the number of heat waves in a given year. That's something we've talked about a bit internally, including some ways to do it.

The question is more appropriately covered in our reliability, stochastic modeling, and not necessarily something that we would build into a base load forecast. But once we have a properly calibrated load weather relationship model, we could, say, go to 2021, where we saw a couple of heat waves that were pretty geographically widespread, use that as kind of a base weather system, run that through the load weather model, and come up with a load forecast where we are using a period of time as opposed to using normal weather or something to that effect.

So, as we do the 2040 hourly forecasts, we're running a daily weather pattern through and that can be anything that we want it to be right now. It has a typical hottest day in each month, typical second hottest day, and down to the typical coldest day. So, it represents fairly the range of weather that we've seen based on those 20 years of history, and the hottest days. So, we've got 20 hottest days; you average them and that's our hottest day.

(Take the hottest day from each of the 20 years, freeze the 20 years, and average them.)

That's what's driving our peak forecast right now. And the day before and the day before it--those things matter in the modeling. So, the pattern matters as well. We can put whatever pattern we want and see what the implication is.

That is captured more in our stochastic reliability modeling. And in terms of the way you know a couple of increased frequency of events affect the system, even if you're putting in a different pattern, it's still normal weather, and it's still within the same operating temperature ranges.

It probably would not have that big of a difference on the general portfolio, depending on the duration of some of those events. Maybe you start to see a bit of an increase adoption of more firm dispatchable resources or longer duration storage. But overall, the frequency of events is that it's not going to change the capacity builds that much.

And then there are parameters in the model that we can look at and anticipate the impact of an additional degree to the day, the day before, and the day after. If we go through those three parameters, there's some number like 20 megawatts per degree. We'd have to look at the slopes to know what those are.

We welcome specific requests; for example, an ask to look at three extreme weather events per year throughout the period, with an increase of one degree per year. We want specific requests that we can put into a scenario development form to make sure that we're understanding the ask correctly.

Update: PNM

The PNM modeling framework and Phase 1 modeling scenarios were discussed during the February 15, 2023 meeting.

The framework for modeling run requests was discussed during the March 15, 2023 meeting.

Asked by Brubaker & Associates on July 6, 2022. View meeting information here.

Initial Response: PNM

Yes. We will do a session about the import limit and also one on external modelling.

If there are concerns about the way we're representing the external systems to PNM, they should be raised. By the time we get to October, the ELCC work is going to be complete; the planning, reserve margin, and calibrations are going to be closed. There will still be time to change those a bit but that session in the fall is going to be more about any information that would make us believe that we ought to change the level of imports that we're putting into the model.

If there are things structurally about the model in terms of the representation of the neighbors and other things, we need to be dealing with them now. We can take a closer look, recognizing there may be some interaction with the import limitation, when we're doing the external systems where the import limit was trying to capture some things that were not being modeled as detailed as when some stakeholders are now proposing.

That overlay of the market availability constraint is because you can't perfectly represent everything, and especially those imperfect deficiencies in the market. It's not like you're bidding everything into a common centralized market, and everything's being dispatched centrally.

So, we're trying to better capture those imperfections and then discuss them. Is it going to get us to the point where we're 100% comfortable that we are capturing everything? Probably not, but we think it's going to be an improvement.

Update: PNM

Topics related to this question were discussed at the January 17, 2023 meeting.

Asked by a member of the public on July 6, 2022. View meeting information here.

Response: PNM

There's not any behind the meter wind generation that we are aware of, or at least not anything readily available to customers in significant quantity to put wind generation behind their meter to use as some type of behind the meter production that offsets consumption at their own meter.

We certainly need to be aware of wind and we'll be modeling wind as a transmission level resource. We are not as familiar with any real way to do distributed wind or behind the meter wind. There's also no specific forecast associated with behind the meter wind additions.

Regarding weather, the impact is big. We can dive into seasonality and other things on wind production a bit more in detail and show some plots. But generally speaking, the heaviest wind production for New Mexico is in the spring, fall, and winter, basically from around Father's Day through the end of the summer when the wind output drastically drops.

Furthermore, there's a much greater wind production overnight and early in the morning; wind production tends to fall off during the middle of the day into the early evening when our consumption is the highest. That comes through in the ELCC analysis when we're looking at developing effective load carrying capability for different resource types. We see that effective load carrying capability for wind relative to when the risk hours are. We see large capacity factors for wind, meaning the ratio of total energy produced throughout the year to its theoretical maximum. We have a pretty high-capacity factor for New Mexico wind relative to a lot of other wind resources across the country.

The major issue is that wind tends to blow when it's not as much needed. You're still left with that gap in the summer, and especially in the early afternoons and evenings in the summer when our demands are the highest. Then, wind is just not contributing as much to meeting those demands, even though it's providing a pretty good energy resource over the course of the year.

Also, other things happen. Typically, with weather, when we get those really, really hot days, accompanied by high pressure heat domes, which typically coincide with very little wind. On those really stressful, high temperature days, you tend to see very, very low wind production.

When you get really, really cold days, there are times when wind resources have to be completely feathered. You're not dispatching if ice builds up on the wind turbines or other things occur that take them outside of their operating conditions. We saw that in Texas a bit during the cold weather event in 2021. And to some extent, we saw some curtailments of wind resources in our system because they got outside of the operating conditions for which they were engineered.

Asked by a member of the public on July 6, 2022. View meeting information here.

Response: PNM

We need to keep all options on the table.

In particular, some of those natural gas resources that are only used in case of emergency, 2-3% of the hours of the year, and renewables are things that enable the transition. As we're moving down this path of decarbonization, we don't need to add combined cycles. At least PNM doesn't need to add a combined cycle or anything that is going to be producing lots of kilowatt hours over the year.

Having those resources that can ramp up quickly and provide energy when needed, under extreme circumstances, and then ramp back down, provides a safety net and a backup to the system as we're going through this transmission transition. These are things we need to keep on the table and in the public eye because people don't really understand them.

Sometimes, there's a misconception about a kilowatt hour versus balancing the system in real time--understanding what the inertia and other system stability requirements are. We will get to where we can do it without fossil fired resources. This is supposed to be a transition. We don't want to take too big of a first step that can end up leading to some type of reliability event that we could have prevented.

Asked by a member of the public on July 6, 2022. View meeting information here.

Response: PNM

Generally, there needs to be enough resources under PNM's control to ensure that we can reliably operate the system. With all of that solar coming in, especially behind the meter, we get back the idea of having to have a lot of distributed storage and things that PNM can control in real time to operate the system reliability.

Ultimately, if you're going to have that much behind the meter solar generation, it would seem that you can't have it all with a total aggregate retail rate and net metering credit because there's not going to be enough left on the system. You'd have basically less than half the system paying for all the cost and then having to pay other people for that production when the real value of that energy is not the total retail rate.

Seeing that we have to recognize the ways we have to align the pricing structures in the payments for that distributed energy, what is it really worth to make this all work correctly?

This is a large area that's probably beyond the scope of the IRP per se. There will be grid modernization--the grid of the future. These discussions will happen at the policy level with decision makers. As you move towards this new system, fundamentally, pricing cost allocation, the way the utility interacts with its customers and handles all those distributed resources. needs to be reexamined and viewed in a different light because it's not yesterday's utility system where the utility is generating power.

Centralized plants and sending energy one way down to the transmission distribution network is going to mean a much more communicative grid and a much more bidirectional grid. In order to ensure that you're really comprehending how that's all going to work and how it's got to be paid for requires a reexamination of the way we view the different components and how we price those out.

Asked by a member of the public on July 6, 2022. View meeting information here.

Response: PNM

We will dive into this more when we do our modeling.

When you add a battery to the system, when it's charging, it's adding load to the system; when it's discharging, its serving load. We're capturing that dynamic as well the losses that come with everything.

Depending on the chemistry, or the type of energy storage, that loss is greater or less. If you're talking about lithium ion, typically, you've got an 87% round trip efficiency, if you want to fully charge your battery from a full discharge state, Let's just say it's a 100 megawatt 4-hour battery, so 400 megawatt hours. Put in 400 megawatt hours to hold 400 megawatt hours. You've got to put in 400 megawatt hours grossed up by another 15% to cover that loss.

And then once you put in all that energy--and it takes time to put it in because there's a charging rate if you have a 100-megawatt lithium-ion battery--you cannot charge more than 100 megawatts in a given hour. It's going to take over four hours to charge up that battery and that's going to be load on your system when it's charging, in order to be able to discharge for four hours later. You could discharge it over four hours, or over eight hours, but you're limited to that single volume of 400 megawatt hours in this example.

Looking at other chemistries--pumped hydro, for example, is typically 80% round trip efficient. Some of the other things we saw in the RFI from last year were that when you look at compressed air storage or flow batteries, you start getting down into 70%, 60%, and 50%. They all have different charging rates.

So, all of this is built into the modeling in terms of when we're picking the resources that go into the portfolio. The model fully sees and fully takes into account the charging rates, the discharging rates, the amount of energy, the contribution, the competing capacities--all of it. At the point when you're really, really down to that deep decarbonization, the ability to charge your batteries becomes completely limiting, especially when you have renewable droughts or other weather events that don't allow you to simultaneously fully charge your storage devices while meeting your load at the same time.

We are taking into account these different characteristics of the different technology types as we move forward. We've said in a couple of stakeholder meetings now that it's easy to think about storage--short duration and long duration storage are terms tossed around quite a bit--but eventually we need to consider the total volume of energy storage that we need and the charging rate we need to be able to store that volume of energy under certain conditions when we get into the winter with a predominantly a solar system producing much less energy because of shorter daylight hours.

If you need to charge up all of your storage in a shorter amount of time from solar, if it's a shorter daylight hour, you have to have a much higher charging rate than you might need in the summer. There are a lot of dynamics that go into this but each type of storage--batteries, pumped hydro. or other chemistries--has different characteristics. It is a matter of trying to figure out what types you need, where to locate them, and how to maximize that for efficient use of the system.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Response: PNM

The whole purpose of the IRP is to determine the mixture of resources, both near term and long term, which will best fulfill the needs of the system at the lowest reasonable cost while meeting all of our environmental constraints.

Certainly, as we you start to shift that peak or that risk out of overnight and into the early hours of the morning, a natural gas resource can meet that requirement. Storage can also meet it, if you have enough--and it's not just enough capacity of storage, but enough stored energy to last you all the way throughout the overnight when you've got to have enough resources on your system to charge while serving your other loads.

Adding enough storage will become a question of economics. When we get to 2040 and have to be 100% carbon free, it will be predominantly storage unless there is some type of hydrogen--new green hydrogen--or non-methane emitting renewable fuel that you can put through existing turbines.

Otherwise, you're going to have a lot more storage--whether it's pumped storage or lithium or flow or any other technology that's out there--but you're going to have to have enough capability of megawatt hours stored, plus some reserves to ensure you can serve those overnight loads. You might need to be able to do it for two or three days in a row.

If you want to be resilient to protect from a renewable drought, then you're going to have to have enough power electronics charging capability to charge quickly enough during periods of overproduction, to charge all of that storage up to have it ready to go, as opposed to flipping on a gas generator.

So, it can be done both ways. We're going to examine both ways. And we're going to report on the pros and cons of both throughout this IRP process.

Asked by NMPRC on July 6, 2022. View meeting information here.

Response: PNM

If we're doing a full-blown RFP that's one thing. We need to make the distinction that an RFI and the integrated resource planning process are different from an RFP.

If we're conducting an RFP, which would lead to the actual procurement of new resources, when a developer submits a bid, they have to submit as part of that bid what their transmission costs are. That can be done by a transmission analysis performed by them or by some third party. There are a lot of engineering firms that can do that. That information would then be reviewed by PNM. If they don't submit transmission costs, or the transmission costs they submit seem unrealistic, they will be replaced by transmission costs and upgrade costs that are developed by PNM's transmission department for purposes of valuation of that RFP for the RFI.

Your question is if there's enough information in the RFI to have specific locations where we can come up with what that transmission component might be. As these offers are coming through the RFI, they'll be modeled in the IRP; we'll have to make some assumptions about where those resources might be located.

If they're all predominantly storage resources, unless we know for a fact they're going to be up in the Four Corners area, we'll apply some transmission adjustments to those. But they'll all be pretty consistent across the resources because, again, this is a pretty generic analysis.

This is not an RFP evaluation; it's an analysis where we'll be looking for the general trends. And if we start to see from these general trends that a storage technology that has, for example, a week's worth of storage duration seems to be economic--we then might be in the 2028-2033 time frame--we might put that in the action plan, and RFP will then seek to get very specific project information, including transmission costs that we would evaluate before we propose a procurement.

To the extent that developers are going to know what the transmission adjustments in the IRP are-- in the 2020 IRP transmission assumptions were in Section 7, showing the potential candidate resource transmission lines and what those costs were--that information is available, at least looking back at the 2020 IRP.

We can certainly be a bit more specific about it as we're developing the assumptions this time, but the developers have already submitted their responses to our RFI. They can massage those a little bit between now and September. Ultimately, we're going to be taking a look at that information and making our own adjustments to it to make sure that it's representative of what the additional costs would be for transmission.

It's going to be very generic. We don't have interconnection points. We don't have full load flow and other transmission studies that you would do through the RFP process.

Asked by Sandia National Laboratories on July 27, 2022. View meeting information here.

Initial Response: PNM

So, what we mean by generic resource options is, there's a difference between generic resources and very specific resources that we would receive in a request for proposals.

So, by generic resources, all we're saying is that whether it's solar or storage, or wind or natural gas, turbines, or whatever other technology you want to think about, any of the resources that we're putting into the IRP, are not going to be specific resources from an RFP that would have, say, a spot in the transmission queue, and have a very specific location where they would be interconnecting, and then have a specific cost associated with that resource that's based on a bid offered into an RFP.

It would be a generic representation of that particular technology type that would have a representative cost to it. It would have an idea of the operating characteristics, but it's just not something that's specifically out there in our transmission queue. It would have an idea of the operating characteristics, generic siting costs, and construction expenses and an expectation of what property taxes, permitting, and interconnection would be.

Asked by InterWest Energy Alliance on July 27, 2022. View meeting information here.

Response: PNM

This is not a software issue but a hardware issue. The simple answer would be you could throw more and more and more horsepower at it (the problem), but it doesn't necessarily mean that you're going to get to a better solution all that much quicker. The algorithms that are used underneath of (the current software(s)) are highly parallelizable; however, if you were to try to put all of this into memory at once, the problem is scale--when you're talking about just a binary integer problem, binary mixed integer problem, the problem size and complexity scales with two to the N, where N is the number of binary variables, if we have 20 years representation in there, and we have even just our system size and say you've got 300 different resource candidates, and some of them are thermal units like on the existing system.

Refer to September 24, 2019, IRP presentation when we were talking about problem size that's got 150 zeros after it in terms of the number of different choices that are out there. And you could paralyze this over hundreds of different computing nodes, but it doesn't necessarily mean you're going to get to the answer quicker or a more optimal solution. As for cloud computing, there's a misconception out there that with cloud computing, that we can just go out there and throw everything into these problems at once, solve it, and get the perfect solution. That's just not the case.

The computing technology that will allow us to make very significant progress to solving these types of problems much, much quicker is quantum computing, where you can represent variables not in a binary state where current digital computing works and you’ve just got processors that use “bits” that represent all values in terms of ones and zeros, where quantum computing is not limited by binary states and represents values using complex quantum mechanics.

That type of computing infrastructure will allow you to solve these problems much, much quicker. There's just not that much out there, that type of computing. It's still very early in its infancy and being worked on. The computers require significant engineering infrastructure to house the computer to ensure nothing interferes with the quantum states of the processors and commercially available computers as well as the reprograming of software to run on quantum architecture are still nowhere near ready for commercial deployment.

Asked by Sandia National Laboratories on July 27, 2022. View meeting information here.

Response: PNM

These results are using a zonal model. We're not using a copper sheet model.

Yes, it'll be interesting to move forward and see what the nodal model does. What we can say is that with the nodal model right now, if we wanted to run a full representation of the entire western interconnect, enforcing full commitment of the resources, just for production costs, it does not include capacity expansion.

A single year run takes a little over 24 hours to solve. So, you could extrapolate on that and say to do 20 years we're going to need more time. And yes, we can parallelize some of that. Maybe year one doesn't clearly need to lead to initial conditions for year two.

But then if you wanted to throw the capacity expansion on top of that, that's a really, really big problem because you'd have to come up with some representation of the transmission system. Then, on the DC load flow side to put into the capacity expansion, force all those constraints, may be something that is just computationally intractable.

We'll be doing some testing on that going forward. It may take a year and a half to develop some simplifications and come up with a more constrained zonal model based on information you glean from the nodal model.

There might be some other things you have to do but, currently, the way things are typically done is you're not doing a nodal capacity expansion merely due to the computational intractability.

Asked by Sandia National Laboratories on July 27, 2022. View meeting information here.

Response: PNM

That's certainly another approach, We could force everything that's $35 or less, or $50 and less, and still have the $50 bundle as a choice variable. Or, instead of just doing $50, do 50, to 60, to 70, to 100 and divvy that up.

But the one thing we see here (Slide 14) is, as we go out in time, the very small tranches were actually the highest cost tranches. So, we need to make a note to go back and double check and make sure that the color scale on this slide is correct.

But, as we're moving up in time, generally what we saw is the amount of available energy got smaller.

Asked by CSOL Power on July 27, 2022. View meeting information here.

Response: PNM

We are not taking any options off the table.

We did have some thermal storage offered in an RFI last year. The concepts were not fully developed enough for modeling, unfortunately. We're still going through the RFI this time. If there's enough detailed information for us to put that into our Integrated Resource Plan, we certainly will.

We are not discounting or precluding any types of storage. Using existing or new technologies, we have to make sure we have enough detailed information to model accurately, or as best as possible.

Asked by CSOL Power on July 27, 2022. View meeting information here.

Response: PNM

The answer to that is no. We were taking the renewable production that was typically used in our, reducing the renewable production, but keeping the load at the same level as before.

That might not be a 100% correct assumption, but part of it is due to the expected proliferation of behind the meter generation such that when we have a reduction, say, in solar, we're going to see higher loads due to the reduction in the behind the meter solar that's reducing what's seen at the meter typically.

Asked by InterWest Energy Alliance on July 27, 2022. View meeting information here.

Initial Response: PNM

So, there are two projects that we’re aware of that were offered into the RFI last time. The information associated with evaporative losses was presented in the disclosure of the RFI and the public advisory process last year. There is a pretty reasonable amount of evaporative losses.

There are two projects that are currently going through the Berg licensure process that we’re aware of in the desert Southwest here, in terms of the water availability during summer peaks. That really gets down to your question about the evaporative losses. It would be a one-time fill of how many acre feet. We can go back and check the presentation from around January 2020.

So, once you’ve got the water filled in the water rights, I believe one or both of these projects might have been on tribal lands, and the water would be coming through the water rights and supportive of coming from those tribes that would be in support of these projects. And then there would be evaporative losses, but beyond the evaporative losses, it’s more of a closed loop system. It’s not within the river networks.

With monsoon failure, again, these are one time fill and then you’ve got the evaporative losses to account for each year.

The pumped hydro assumptions were covered in the 2020 presentation and the 2020 IRP. There was information as well within the IRP write up. We need to go back and double check if the evaporative losses were fully documented in the IRP.

Update: PNM

The evaporation rate and pumped hydro assumptions for RFI response in the 2020 IRP were not disclosed. PNM has researched the evaporation rates associated with pumped hydro systems and can provide the following information:

Pumped hydro systems can be open or closed loop: An open loop system is connected to a flowing water feature (like a river), while a closed loop system is not (the same body of water is moved back and forth between reservoirs). Evaporative losses from the reservoirs will depend on a multitude of factors, including the climate and area in which a project is sited, the size of the reservoirs, and whether or not those reservoirs are covered. Coverage of one or both reservoirs can substantially reduce evaporation.

PNM issued an RFI for Resources Available for Future Generation in March 2022 and received two responses from pumped hydro storage developers. Both responses described a closed loop system with an initial reservoir fill of approximately 5,000-acre feet, with expected refill due to evaporation of about 500-acre feet per year (~10% of initial fill) if both reservoirs were left uncovered. However, both proposed projects included a plan for coverage of at least one reservoir to control evaporation. Other water discharge was estimated to be negligible.

A presentation covering the RFI responses was given on October 17, 2022

Asked by NM RETA on July 27, 2022. View meeting information here.

Response: PNM

The ETA between 2030 and 2039 requires us to have 50% of our retail sales coming from RPS [Renewable Portfolio Standard] eligible resources. From 2032 to 2039 there are also requirements that we are serving our system with an average carbon intensity of 200 pounds per megawatt hour or less. So, those two items would be reflected in these simulations.

This is not something that we need to dive into in too much detail at this point--or what the total amount of renewables are. This is more a proof of concept on improving the long duration storage modeling.

The best answer to some of these questions can be found by reviewing the scenarios in Appendix J in the 2020 IRP, where you could get an answer, based on the scenario and sensitivity, regarding what the total amount of renewables on the system were versus other resources.

Asked by New Mexico State University on July 27, 2022. View meeting information here.

Response: PNM

What we're talking about is one of the parameters within Encompass called net inflow and net outflow in the capacity expansion model.

When we're looking at the amount of energy in excess of what was dispelled from the reservoir in a given month, what are we expecting the net increase in the reservoir level to be from month to month, or the net decrease in the reservoir from month to month, would be an input for the capacity expansion model to make sure that there was a representation.

The capacity expansion is looking at a representative on peak day and off-peak day for each month. And then, based on the number of days in each month, it is scaling up the operational characteristics from that representative on peak and off-peak day to come up with a representation of what the total costs and total operating parameters were, based on that simplifying assumption, even though it is doing an hourly piece and ensuring that the chronology is maintained.

Now, one of the ways that Encompass maintains the chronology for resources within the capacity expansion model is that it will say that the last hour of a month must be equal to the first hour of a month. And that gives it a kind of cyclical chronology. And you're not saying. "Okay, well, I could go from, say, August 17 to September 11 and then back to August." Rather, you're always doing a loop back of, say, August before moving to September.

Because of that, you have to give it an idea, then, of what you would expect--the net position relative to that starting and ending monthly or that it would be increasing or decreasing to allow for these seasonal shifts, or month to month shifts of energy.

So, we can run a simulation that gives us an idea of a full year memory--the entire problem is going into computer memory at once, giving it perfect foresight of all of the conditions as it's solving that problem simultaneously for each of the variables.

We take that information and then feedback from it to better represent the resource and the capacity expansion. That will then allow the model to give a better idea of which additional, renewable, or other resources are needed or not needed, given the longer-term storage resource.

Asked by NM RETA on July 27, 2022. View meeting information here.

Response: PNM

The cost by technology may vary dramatically.

There will be a cost tied to each technology type when we're looking at generic resources. So, there would be a capital cost variable operating cost, fixed operations, maintenance cost, and safer pumped storage--which would differ from lithium-ion storage, which would differ from combustion turbines, which would differ from any number of other things.

Each individual generic technology type is represented with its own individual cost, operating parameters, and efficiency cycles.

Asked by Sandia National Laboratories on July 27, 2022. View meeting information here.

Response: PNM

There is no minimum duration requirement per se. We are doing this as a proof of concept. This particular proof of concept is looking at a rather large, but known, potential pumped storage hydro project that was a 1500 megawatt under 1000 gigawatt hours, so maybe almost 70 hours of duration.

There are other technologies out there that we're aware of that are 100, 150, or more hours of duration--lithium, you can just stack more cells on--and so, we're not looking at this and saying there's a minimum duration requirement to qualify as long duration storage. What we are looking at is: What are the different technologies out there, and how do they, given their efficiencies and other things, start working within the context of our system?

We've said this in different stakeholder meetings, and we think that really what we need to do at some point is disaggregate the idea of duration. You need to have an idea of what the total volume of energy storage and megawatt hours are going to be on your system. Then, you should have an idea of the most constrained periods, which are going to be--if you're looking at charging from solar--mostly in the winter, when you've got the shortest daylight hours.

And what is the charging rate? If we will need to fill storage, we need to have that volume of storage necessary to meet hourly, daily, weekly, and seasonal demands going forward. So, there's no prescriptive duration per se that denotes long duration versus short duration versus medium duration.

We're going to need all of those on our system and we're looking at the modeling techniques that will best allow us to compare the tradeoffs of costs and benefits associated with those different technologies.

Asked by a member of the public on July 27, 2022. View meeting information here.

Response: PNM

We're going to be focusing on the water associated with the pumped hydro, as well as the utilization of water by the other parts of the system within other generation technologies. We agree that if we want to have a fully sustainable society, we're going to have to start looking at closed loop systems, including under underground systems for water delivery.

That doesn't necessarily mean we're going to limit everything. Trying to fix leaking underground pipes when they're buried is pretty difficult. So, there's a lot of work that needs to be done overall to move to a truly sustainable society. Right now, we're obviously focusing on the electric system here in New Mexico.

Asked by CSOL Power on July 27, 2022. View meeting information here.

Response: PNM

We are considering all options at this point. The industry is looking at hydrogen, considering the modeling techniques to make sure that we are looking at this in the most rigorous way. Most utilities out there, if we look at them, are keeping hydrogen on the table as a mechanism for energy storage and it could be part of a decarbonized system.

We believe we are in line with the industry view that this should be considered as part of an IRP analysis.

Asked by Sandia National Laboratories on July 27, 2022. View meeting information here.

Response: PNM

The payback is the term that's being used for the amount of energy being put into the system to be converted and stored.

So, the round trip on the hydrogen that we've got here is roughly 28% round trip efficiency. We've got to put in, say, three and a half megawatts from the grid to get one megawatt back to the grid, after being converted, the hydrogen, stored, and then put back through a turbine.

The turbines were roughly 10,000 to 10,500 heat rates, so the turbine itself was about 500, or 33% efficient. Hydrogen has about 1/3 the heat content of gas, and there's the power needed to run the electrolyzer [hydrogen generator]. So, this system here is about a 28% round trip efficiency.

If you compare that to pumped hydro or lithium, those are in the 80, 85, 87% range. And then other storage technologies fall in between.

The 28% may be a bit rosy. We're trying to use some data from manufacturers that are working on developing and selling each of these components; we're relying on some of that data. We don't have an actual hydrogen system on our system, or hydrogen production system on our system that we can actually pull live data from.

The payback is charging energy that includes all of those pieces, to get to the point where it can, then, come back to the grid.

Asked by InterWest Energy Alliance on July 27, 2022. View meeting information here.

Response: PNM

Those results are in the 2020 IRP at the end of Appendix M.

The other things we have been talking about are those import assumptions, especially out into the 2035-2040 time frame. We do not expect that there's going to be near the surplus of energy in the market, especially during non-solar producing hours.

If we consider the transformations of most of the systems in the West, you're building in assumptions that we can rely on our neighbors to charge our storage devices, or that they would potentially sell us energy out of their storage devices to help us meet our net peak loads. We think this would be an incorrect assumption, until we can move forward in time and see what's really going on.

As a utility, we know that if we only have four hours’ worth of storage, and we’re not sure whether we’re going to need it in a few hours, we're not going to sell that to somebody. Right now, and going forward, the predominant source of energy, as we saw from the regional resource adequacy study performed by E3, is going to be solar and storage additions.

So, the idea that we're going to have a lot of available imports to charge our storage devices, especially during off peak, is just something we don't think we can support.

Asked by CSOL Power on July 27, 2022. View meeting information here.

Response: PNM

We're showing a proof of concept on the 100% hydrogen utilization in a year far down the road, towards the end of the 2030. These are once we get to a carbon free system.

Blending presents its own unique characteristics: There is work to be done in terms of modification of plant equipment, pipelines--all the things that would need to be accommodated for hydrogen blending. Also, volumetrically, hydrogen contains 1/3 of the heat content of natural gas. So, even if you were to do a 50/50 blend, volumetric-wise that doesn't represent a reduction of carbon by 50%.

So, in light of pathways to 100% carbon free, blending doesn't really get you there. Blending might reduce a little bit of carbon, but you'd have to volumetrically add in 80 or 90%-- volumetrically blend 80 to 90%, hydrogen relative to 10 or 20% gas just to do 50% reduction in the carbon emissions from that type of setup.

From the modeling we've done, all of the graphs are from 100% hydrogen.

Asked by CSOL Power on July 27, 2022. View meeting information here.

Response: PNM

There are facilities in operation today that can do this. PNM does not have any on its system currently, but there are certainly turbines out there that can burn 100% hydrogen. There are some that will need additional work to get them up to burning 100% hydrogen, depending on which turbine technology and company you are looking at. There is certainly already the ability to electrolyze water into hydrogen and store it.

So, the technologies exist. It's really a matter of which turbine you want to use, what the costs are, and where we see those going.

Asked by Brubaker & Associates on July 27, 2022. View meeting information here.

Response: PNM

For some additional information on the EE (energy efficiency) bundles and how they're developed, AEG will return to discuss that when their study is complete. But you can see some of the information in the August 25 presentation in the 2020 IRP.

Each bundle comprised a number of different measures. For each year, the characteristics of each measure are used to determine what the weighted average life and weighted average price of that bundle is. Certainly, one of the ideas that we've mentioned earlier was that perhaps it makes more sense to break apart that $50 bundle and do a few different price tranches—50 to 60, 60 to 80, and so on—and then, for each deal, determining which price points you wish to measure and what the overall shape of each bundle would be, given the measures that are in that bundle and those price points.

We can consider all of these ideas with AEG and provide them direction on the ways we want to do the different tranches of the bundles.

Asked by NMPRC on July 27, 2022. View meeting information here.

Response: PNM

Hydrogen is not a renewable energy resource under the Renewable Energy Act, so hydrogen in and of itself, whether it was produced by renewables or produced through some other process like steam methane reformation, would not count towards meeting the RPS.

Any hydrogen production of generation would have to be a part of the 20%. If we're looking at 2040 and beyond, it would have part of the 20% of generation that could be attributable non carbon emitting resources, but not necessarily renewable resources. Depending on the resources that are used to produce hydrogen, whether they are renewable resources, or whether you do it through steam, methane reclamation, or some other process, additional renewable resources on the system could count towards the RPS and increase the percentage of RPS that we're meeting.

That being said, the Energy Transition Act requirements relate to retail sales. And it's not necessarily that the loads from electrolyzers would necessarily be retail sales. That could be considered station service or other things.

So, there are a lot of little nuances that would go into this issue and how the regulator's would view each of those pieces. But the RPS is a percentage of retail sales. And it is related, not to life cycle, but specifically to the amount of energy we are required to deliver to the retail end use customers.

Whether additional regulations or laws come through in the future that talk about full supply chain emissions and other things remains to be seen. In the Integrated Resource Plan requirements, we have to meet our renewable portfolio standards that are relative to generation production by renewable eligible resources under the Renewable Energy Act, and that ratio of the production to retail sales--whether it's 20%, 40%, 50%, or 80%, corresponding steps from 2020, 2025, 2030, and 2040.

Asked by Grid Strategies on behalf of InterWest Energy Alliance on July 27, 2022. View meeting information here.

Initial Response: PNM

If we go back up and look at these plots (Slide 13), what we actually see is that there's greater storage utilization in the partial than in the full commitment. We attributed that to the fact that, in this situation, you could commit at lower than the actual minimum load.

So, when we think about this, there's a binary variable that represents whether or not a unit is committed. Under the full commitment, that binary variable in a given hour would represent a zero or a one but in a partial commitment, It could represent, say, a point for the 40%. That 40% would then be applied to the minimum loading of, say a CT, if it's minimum loading, say it's 100 megawatt CT, and its minimum loading is typically 40 megawatts.

Now, rather than doing that, if you do the partial commitment, it's 40% of 40, or 16 megawatts. So, then we can have our thermal unit committed at a lower level, which allows for greater storage utilization. If we still need to commit that thermal unit under full commitment, but it's committed at a higher minimum load because the percentage is no longer applied--it's either a zero or a one--you actually end up seeing a little bit lower utilization of storage.

PNM continued.

We've done some testing on the capacity expansion and partial commitment. And for the most part, we're seeing the same resources, the same expansion plan, and in both scenarios, we're seeing the same resources being added on both sides.

So, from at least the capacity expansion side, we don't think we're missing, anything,

InterWest Energy Alliance continued.

I can see how it can go both ways. It does look like in that slide that it reaches a little bit lower dispatch in the earlier years in the partial commitment, but then it does do better in the last year.

We're basically going to be curtailing renewables because you've got your pure thermal generation running at its minimum. And the storage can provide value by charging and absorbing what would have been renewable curtailment, if the minimums are lower, removed entirely, then that benefit is less appreciated.

But we can see also how that can be offset by what you were talking about, that effectively, the partials give you lower minimums on the thermals.

PNM continued.

The thing to take away is that, in our testing, whether we're running a partial or full commitment on the capacity expansion itself, it is just computationally intractable. But that is not the case when we do some limited tests. And were we to do, say, a full commitment on a shorter time period, or reducing the system builds, it ends up being the same whether we're doing partial or no or full commitment.

That gets into the same idea we had here (Slide 12): having a three-step process where we're starting with a simplified solution.

When we have our more simplified representation and settings, and when we have to put more and more years of data and choices into the model, then, as we move forward and move down, we've got the expansion locked. But we need to make sure we're getting the right representation of long duration storage. Then, we can move down further and do a full commitment.

So, by the time we get to the end, and the overall system metrics that we're reporting, we've gone through various levels of details and got down to a full commitment.

We are getting pretty comfortable with the way this is working. There's no computationally perfect solution at this point. But all the tests that we're doing right now at least are showing that this process is working very well. And by the time we get to the end, we do have the full representation of all the commitment decision variables when we're running the production costs.

Asked by NMPRC Utility Division Staff on July 27, 2022. View meeting information here.

Response: PNM

Discharging at a lower rate would not have much effect on the batteries. Typically, the factors, at least with lithium, that most affect the overall life of the batteries are if you go through deep discharges, multiple cycles per day, actually keeping energy stored in for too long.

A lot of the vendors are telling us that over the course of a year you want to have a 40 to 50% average state of charge. So, discharging it over a longer window would actually reduce the number of cycles you would have in a given day or over a given year. It may actually limit the degradation as opposed to add to it.

Asked by NM RETA on July 27, 2022. View meeting information here.

Pending PNM Response.

Asked by Sandia National Laboratories on July 27, 2022. View meeting information here.

Response: PNM

There is no minimum duration requirement per se. We are doing this as a proof of concept. This particular proof of concept is looking at a rather large, but known, potential pumped storage hydro project that was a 1500 megawatt under 1000 gigawatt hours, so maybe almost 70 hours of duration. There are other technologies out there that we're aware of that are 100, 150, or more hours of duration--lithium, you can just stack more cells on--and so, we're not looking at this and saying there's a minimum duration requirement to qualify as long duration storage. What we are looking at is: What are the different technologies out there, and how do they, given their efficiencies and other things, start working within the context of our system? We've said this in different stakeholder meetings, and we think that really what we need to do at some point is disaggregate the idea of duration. You need to have an idea of what the total volume of energy storage and megawatt hours are going to be on your system. Then, you should have an idea of the most constrained periods, which are going to be--if you're looking at charging from solar--mostly in the winter, when you've got the shortest daylight hours.

And what is the charging rate? If we will need to fill storage, we need to have that volume of storage necessary to meet hourly, daily, weekly, and seasonal demands going forward. So, there's no prescriptive duration per se that denotes long duration versus short duration versus medium duration.

We're going to need all of those on our system and we're looking at the modeling techniques that will best allow us to compare the tradeoffs of costs and benefits associated with those different technologies.

Initial Response: PNM

That's something we can definitely look into and see if we can find any information. There are some closed loop test systems out there. If anybody's doing that at utility scale up, it's just in test systems at this point.

Update: PNM

We haven’t been able to find specific discussion regarding projects that implement a water recovery system after hydrogen combustion. We expect as time progresses, more information will become available.

For more information concerning current pilot projects, Clean Energy Group produces a list of hydrogen pilot projects across the US which can be found using this link: https://www.cleanegroup.org/ceg-projects/hydrogen/projects-in-the-us/

Asked by New Mexico State University on July 6, 2022. View meeting information here.

Initial Response: PNM

We understand the question as asking if we could somehow work into the forecast an increase in the frequency and the number of heat waves in a given year. That's something we've talked about a bit internally, including some ways to do it.

The question is more appropriately covered in our reliability, stochastic modeling, and not necessarily something that we would build into a base load forecast. But once we have a properly calibrated load weather relationship model, we could, say, go to 2021, where we saw a couple of heat waves that were pretty geographically widespread, use that as kind of a base weather system, run that through the load weather model, and come up with a load forecast where we are using a period of time as opposed to using normal weather or something to that effect.

Initial Response: Itron

So, as we do the 2040 hourly forecasts, we're running a daily weather pattern through and that can be anything that we want it to be right now. It has a typical hottest day in each month, typical second hottest day, and down to the typical coldest day, So, it represents fairly the range of weather that we've seen based on that 20 years of history, and the hottest days. So, we've got 20 hottest days; you average them and that's our hottest day. (Take the hottest day from each of the 20 years, freeze the 20 years, and average them.)

That's what's driving our peak forecast right now. And the day before and the day before it--those things matter in the modeling. So, the pattern matters as well. We can put whatever pattern we want and see what the implication is.

PNM continued.

That is captured more in our stochastic reliability modeling. And in terms of the way you know a couple of increased frequency of events affect the system, even if you're putting in a different pattern, it's still normal weather, and it's still within the same operating temperature ranges.

It probably would not have that big of a difference on the general portfolio, depending on the duration of some of those events. Maybe you start to see a bit of an increase adoption of more firm dispatchable resources or longer duration storage. But overall, the frequency of events is that it's not going to change--the capacity builds that much.

Itron continued.

And then there are parameters in the model that we can look at and anticipate the impact of an additional degree to the day, the day before, and the day after. If we go through those three parameters, there's some number like 20 megawatts per degree. We'd have to look at the slopes to know what those are.

PNM continued.

We welcome specific requests; for example, an ask to look at three extreme weather events per year throughout the period, with an increase of one degree per year. We want specific requests that we can put into a scenario development form to make sure that we're understanding the ask correctly.

Update: PNM

The PNM modeling framework and Phase 1 modeling scenarios were discussed during the February 15, 2023 meeting.

The framework for modeling run requests was discussed during the March 15, 2023 meeting.

Asked by New Mexico State University on July 6, 2022. View meeting information here.

Response: PNM

Yes. The SERVM model that does our stochastic reliability modeling has 40 years of historical weather data. And it does stochastic variables, stochastic analysis on the load, as well as the renewable production related to the weather.

Take 2011, a year mentioned here as extremely hot in the desert Southwest. If it was sampling from the 2011 weather year, the model would then pull out the weather and apply that weather to the load as well as to the renewable production for a given sample day. You'd have that correlated effect of that weather year being applied to the base load shape, and the base, renewable production shapes with that stochastic weather uncertainty.

There are other stochastic variables--forced outage rates, economic uncertainty, other things in the stochastic model as well. When all are put together when we run that model, there are 40 different historic weather years, and a number of other stochastic variables. We end up having a little over 1000 single runs to represent stochastic hourly production cost runs. There are actually five-minute production cost runs that assess production cost and reliability for a given calendar year.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Initial Response: PNM

The last time we did not assume that there was no ability to purchase from our neighbors during times of maximum constraints we did assume that there was a limited ability. We didn't just allow for unfettered transfer of energy within the model.

When we're doing the IRP, we have to look at PNM retail, and we have to make certain assumptions about the boundary conditions outside of PNM retail. There's more load and more resources in the PNM Balancing Authority (BA) and then there are other loads and resources even beyond what we saw in 2020. And that's where the assumption that you're referring to came about-- when we had that geographically wide heatwave in 2020, I believe is August 14-20.

There were maximum constraints in the market, and we were not able to purchase more--the day of maximum strain was August 18, or 19. when we were not able to purchase. There was one hour when we were only able to purchase 25 megawatts; another hour, we're only able to purchase 75 megawatts, despite having basically an unlimited price; we were paying over $1,000 a megawatt hour, and we just weren't able to get anything.

And so, what we've been seeing, and we've been talking about is that there has been a drastic decrease in the number of counterparties available in the bilateral markets, there has been a drastic decrease in the number of transactions. We know that there are more and more retirements of resources going on and systems are getting constrained. We saw in Arizona recently that a planned natural gas plant expansion was denied.

We are talking to our traders every day and understand what the market conditions are like. And as more and more firm dispatchable resources get retired, as more and more systems you have predominantly are solar and then storage for capacity going forward, we do believe it is less likely that utilities, especially in the near term, are going to be willing to share energy if it's coming out of an energy limited resource like storage.

So, we're not making any decisions yet on what our assumption around the market availability for resources would be for times of maximum constraint in our reliability modeling. We'll revisit that after the summer and see if there's any new data to consider. Right now, we're thinking we're still going to use the same assumptions as we did in the IRP last time.

In 85% of the lowest hours, there were no constraints in the model for that. And when we look at the top 85 or the top 50% of load days, if it wasn't a gross load period, the market was limited to between 200 and 300 megawatts of market assistance during those peak gross load hours. And then when we got into the peak net load hours that were reduced down to 50 megawatts, consistent with what we saw during the 2020 heatwave when we weren't really able to purchase anything, and it was those hours, as the sun was setting and there were maximum drawn resources into California and otherwise, when we talked about some of the limitations in the model as well.

We're trying to update the modeling of our neighbors--the change in their resources based on their IRPs so that way, we can understand some of the better implications of how the market dynamics may change as regional systems change, not just as PNM's system changes. We were only modeling one timeline away, say Arizona, for example. Most of our imports come from west of us from Arizona. We got negligible transmission capacity coming in from the east and from the north. And there's not much availability to be able to bring things in across white path 47 from the south.

So, most of what we get is coming in from the west. And Arizona also sells a lot into California. And we didn't have California in the model as a sink. All of that energy that might have been excess in Arizona was assumed to be made available to PNM at a perfectly efficient market, which is just a simplifying assumption.

That's why we have to look at some of the actual data of what is occurring during these times of key constraints and not just say, well, anything a model says is 100%. And that's some of the flavor behind what we're looking at when we're trying to take the reliability modeling forward.

But the heat wave analysis per se is something that, as we model PNM loads, we need to consider outside of the PNM retail system when we consider that it is more in the context of what we think we could reasonably count on to bring in from other systems during times of constraint.

The more we take out of our control, the more we sell, we put ourselves at risk. Should we be planning that we're an island? Should we be planning on limited amounts? Or should we plan on unlimited amounts? And should we add to risk to the system?

Is it a balance?

Update: PNM

Asked by Form Energy on November 2, 2022. View meeting information here.

Response: PNM

We've had a few stakeholder presentations on ELCCs and the PRM methodology. There's some specific information in the June 8, 2022, and June 22, 2022, presentations, as well as in our September 15, 2020, presentation from the 2020 IRP.

We can certainly try to address any specific questions you might have. And we'll have more presentations once the ELCC study has finished. But in terms of having anything immediately coming up, unfortunately, we've already gone through some of that information. So, are there any specific questions you might have in that regard?

{Form Energy representative responded that he had nothing further -- He would go back and review the earlier material.]

Asked by NM RETA on July 27, 2022. View meeting information here.

Initial Response: PNM

There's no specific representation of an RTO within the model going forward.

If we take a step back, we'll see that there are two different places where we look at energy markets in the modeling.

The first would be when we're setting up our planning reserve margin requirements to SERVM. What level of market support from external entities outside of PNM’s control are we willing to allow to contribute to the planning reserve margin requirement?

The second piece would be when we do the capacity expansion modeling. We do not allow that, except for whatever that specific reduction to the planning reserve margin requirement is, as an input. We don't allow purchases to be used to meet capacity and energy requirements when determining what the preferred resource bills will be for any scenario, nor do we allow sales to be included. We don't want to have the system being built for speculation; we want to make sure that we're picking the right resources to meet our requirements for our retail load.

That's what we have to do in the IRP--look only at our retail load. We don't even look at the whole balancing area, the requirements under the New Mexico rule, or our retail load in the IRP analysis.

And then when we do the more detailed production costings, once that capacity expansion is finished, and the portfolio for that given scenario is set and locked in, we re-dispatch the system on a full chronological hourly basis every year for the full 20 years. And we allow economic purchases and sales to be included in that there's no restriction in that representation, in terms of the amount of capacity or energy that can be done in any hour, except for what we believe are limitations at the liquid hubs where we trade.

So, we're typically saying that’s roughly 250 or so megawatts. And that corresponds to when we do a lot of our trading; we can typically do 250 to 300 megawatts of economy trades without incurring significant transmission cost. If we go beyond that, then there's transmission or hurdle rates that typically have to be included. That's the general setup.

We do fully anticipate that the West will move towards an RTO in the next 10 or 20 years. It's difficult for us to say exactly when. And it is even more difficult than to say, once they are created, how quickly we can do transmission planning. How quickly then could transmission lines get built?

So, there are a number of assumptions. We are supportive of the idea of an RTO but cannot say specifically when it will occur. And then to assume interconnection capabilities beyond what we already have here today is pretty speculative.

We will discuss some of these things a bit more in a future meeting on transmission modeling.

We've talked about this a little bit in the past when we brought in the Encompass nodal version of the model, which will allow for a full transmission constrained economic dispatch, not just of PNM retail system, not just at the BAA, but of the entire western interconnection. But it's going to be some time before we have that model, fully calibrated. Then, trying to use it going forward is something that's going to take place over time, at least as it works its way into the Integrated Resource Plan.

So, for right now we're focusing on what we've been able to see for economies within our existing operations. And regardless of whether we would be in an RTO or not in an RTO, we would not want to plan the system in a way that's going to be maximizing resource additions for the year to make purchases or sales. We still would have the obligation of finding a least cost solution for our retail customers, depending on how that RTO is set up, whether there's a capacity market, sharing of capacity resources, and other things, would depend on the market design of that RTO.

Update: PNM

Transmission topics were covered during September 13, 2022 and October 6, 2022 meetings.

Asked by a member of the public on July 6, 2022. View meeting information here.

Initial Response: PNM

The transmission issue with wind is predominately related to the fact that there's not really the ability to add wind resources anywhere near the load pocket. And so, when we think about where the good New Mexico wind resources are, they're all out in the eastern New Mexico, Clines Corner, and further east. The transmission coming in from that part of the state is fully subscribed.

In order to get more wind into the system, we wouldn’t need to add more transmission, where the general geography and availability of solar allows for different resources that have solar resources to be added differently throughout the broader part of the state. They may not require transmission. We're getting to the point where the transmission system overall is pretty fully subscribed when you talk about firm transmission service.

And so there may have to be a different way of viewing the way that the transmission system is going to be used and operated. Maybe we need to start looking at energy only interconnects, where you allow for some curtailments, or you got to start putting the storage resources in the load pocket as well as having the resources be able to soak up some curtailments that might occur in order to use the transmission system as it currently exists without adding much more transmission.

It takes a long time to add transmission to what our transmission group will typically tell you; we've got to go through the standard process and build a new 100 mile or 150-mile line, and you're probably talking about a 10-year project from start to finish--from conceptualization, permitting, commission approval. and then actual construction.

And so, all those things we have to factor into the equation. Many think that transmission is going to be something that can get us over the hump of decarbonization. But unless we can build transmission faster, we might need to focus a little bit more on distributed resources until we can get that transmission built.

Member of the public continued.
I was aware of that, and it's always been a question of a concern for me--that transmission building doesn't seem to be a very immediate resolution to anything.

PNM continued.

Yes, you're exactly right. And we would like to be able to build more transmission and upgrade our existing transmission system and the backbone structure. The main PNM transmission lines were all built back in the 60s and 70s. We think that it would be prudent to add more transmission upgrades. The reality is that it's very difficult to do from a regulatory, permitting, and other process perspectives. Just because we want to do it doesn't mean that there aren't impediments to getting it done.

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Response: PNM

The IRP is not a full-blown transmission analysis, and it was never meant to be one. There are things that we can do and things that we can't do.

We addressed transmission hurdles in the 2020 IRP, where there were four candidate transmission projects: one that would increase transmission capability from the Four Corners area, one that would go towards eastern New Mexico, one that would go to northwestern New Mexico, and one that would go south of Albuquerque, but not across cut Path 47 into the southern service territories. We had costs for those such that we knew what resources could generally be added in those different resource locations.

For example, when we would only assume what was available in the east, we said that to do that 800-megawatt transmission line had a cost of, say, $300 million, or X dollars per kilowatt of transmission. And then we would add those X dollars per kilowatt of transmission on to the dollar per kilowatt for wind. And so, the combined cost of the model would show that when making that choice to add wind it was a combination of transmission and capital for wind.

And we said that for wind, in particular, if you're going to have to build that whole big new line, you're not going to do it for less than 400 megawatts. So, we made an assumption that you had to take at least a 400-megawatt wind farm with half of the transmission line, essentially. And maybe there was some other party who would take the other half of the line that wouldn't go into retail rates.

That's another distinguishing feature about the transmission piece: We only look at New Mexico retail in the IRP. All of the transmission that PNM owns and what is in our balancing area authority; half of it is not used to serve our retail system.

So, you have to think about the things that are affecting the transmission system and how that would work when only half of it is actually utilized for the transmission of energy for the retail customers and only half is cost recovered from retail customers. The other comes from FERC jurisdictional

Asked by InterWest Energy Alliance on July 6, 2022. View meeting information here.

Response: PNM

This question gets into the difference between PNM retail and then PNM the balancing area.

The eastward constraints are because we have, aside from needing additional transmission, to bring in resources, say from the east, for new wind. If we wanted to go further east than that, we're up against the AC to DC to AC converting stations that interconnect us into the eastern interconnect. They're on a different frequency; they're asynchronous, essentially, to the PNM system. In order to transfer power between the eastern interconnect and the western connect where PNM is, that power should go through these AC to DC to AC ties, which are very old and not very reliable anymore, and would require significant upgrades in order to allow for greater deliveries.

Once that power gets across the ties, there are additional constraints then to get the power from across those ties to the PNM load centers. There really is a need for us to increase those ties and increase that transmission versus adding resources elsewhere.

The same thing could be said about going up towards the north, but that would all be power that's coming in from neighbors. Are we going to be able to count on that? Are we going to be contracting for long term obligations that would necessitate those transmission additions? And would that be cost effective, rather than building resources closer to our load center, and being able to control those resources

The IRP really is not the right process for assessing that.

Given that there are these fundamental differences between the way the PNM retail system works and how we plan for that versus the way you might think of doing broader regional transmission planning through an RTO, is one of the keys that will help us get to carbon free. But it's not going to be PNM that drives that process. We're just too small of a fish in too big of a pool.

Asked by NMPRC on July 6, 2022. View meeting information here.

Response: PNM

You might infer that somewhat from the wind example. But generally, we're just looking for trends in the IRP. When we get into an actual procurement, we will identify the specific resources and then apply to the [Public Regulation] Commission.

In a countervailing example, when we are looking at storage, or solar things that can be built much more modularly and added closer to the load pocket, we didn't require a minimum 400-megawatt size. There were different transmission options: For example, there was a transmission option looked like it could upgrade the load carrying capability just within the load pocket. And then there were two or three transmission options that were in the west and the north and a little bit in the south.

And because we see much more difference in size on solar and storage, we said that those could be picked up in much smaller increments, and so might marginally add some transmission upgrade costs, but in proportion to the size that was chosen for that specific resource type.

The IRP might say: In X year, we need only 25 megawatts of solar and storage at this location. It would only incur a transmission upgrade cost that was proportional to the dollar per kW cost of the transmission that was associated with the north or west, which was a lower cost than going to the east, but it didn't require that big hurdle in terms of a 400-megawatt size.

That's what we've been seeing in the RFPs as well. There's some work that can be done within smaller time frames. If you start adding those really big resources--200-, 300-, 400-megawatts--those are going to drive significant transmission upgrades. We'll get to a point where everything will drive that, letting you know that the transmission system is getting pretty fully subscribed.

There are little things that the transmission group can do to accommodate some smaller resources, but eventually we're going to run out of those and it's going to drive larger transmission upgrades.