2023 IRP Facilitated Stakeholder Process Q&A
Questions and Answers:
Asked by the Office of Senator Heinrich on May 11, 2023. View meeting information here.
Initial Response: PNM
A very good question.
So, first we'll go through all of the different scenarios that we'll define through the modeling subgroups. We've got a list that I'll share here towards the second half of the presentation on individual resource scenarios as well as what we'll call complex or combinatorial resource scenarios.
We'll define a weighting system through some of the metrics we get out of the deterministic modeling first, in order to say, “Well, which ones pass muster, which ones don't?” And the way we're thinking about that is, for example, we'll have a baseline cost metric, an incremental cost metric to serve incremental load, and then, if we take a P50 portfolio and run it through an extreme weather case, that'll give us, albeit deterministic, a metric on incremental expected unserved energy for that given portfolio.
We can then take the overall realm of portfolios that we're looking at and, based on the results of the analyses described above, whittle that down to a shorter list that we will then run through the LOLE models and resiliency models to come up with some of those loss of load metrics on the stochastic basis and resiliency basis that you're asking about.
Does that answer the question, or do you want to go deeper?
Office of Sen. Heinrich continued.
No, I think that's good for now, but maybe a process diagram, maybe a sketch, would help as to what you described, summarizing what you describe, would be helpful. Thanks.
Asked by Form Energy on May 11, 2023. View meeting information here.
PNM Response:
We are aware of those.
The IRP is not where we determine specific siting of resources; that's done through the RFP process when we look at where these resources would actually be interconnected.
I think that generally what we will end up seeing is that we'll stick to the baseline 30 percent ITC assumptions for storage.
We certainly could consider doing a sensitivity or two that reflected storage qualification for domestic content or other such things, but the actual siting and actual portfolio composition of generic resources that we would be modeling, I would say, we can't do everything.
So, we'll likely stick to the 30 percent and then allow the RFP process in the future to determine, for specific projects, whether they qualify for additional bonus ITC parameters.
Asked by Sandia National Laboratories on May 11, 2023. View meeting information here.
Initial Response: Gridworks
Great question.
We have rethought that process and we’ve put together a modeling engagement plan that has clear dates and steps moving forward that we would like to get to everyone for you to consider for feedback before our next meeting on May 18.
That includes a May 25 date for both possible run requests and possible prioritization criteria, but more importantly, the big plan includes putting together a core team, a modeling core team, that will help process, prioritize, and consider this information with our help to then be interfaced with the PNM IRP modeling team.
So, you'll hear more about that, but for now the dates that we talked about on May 4 will still involve a little bit of movement. We're still working toward the June 15 date, but there will be some interim steps that get taken on by a modeling core team.
Does that answer your question?
Sandia National Laboratories continued.
Yes, perfect.
Asked by Sandia National Laboratories on May 11, 2023. View meeting information here.
PNM Response:
I don't know that we have a specific plot that would show cost versus LOLE.
You would be right that the tighter the reliability constraints, the more cost we would incur.
We could point you to a supply side resiliency study that's on our website that showed if we wanted to start normalizing certain expected unserved energy metrics across a fully dispatchable portfolio versus renewable and storage portfolio, the amount of investment necessary to make those normal, not just on an LOLE or frequency-based metric basis, but on an expected unserved energy basis, would take storage that was 2- and 4-hours in duration and make it 14 hours and 16 hours duration.
And you can kind of think to yourself. “Well, how much more costly is that?”
Asked by Pine Gate Renewables on May 11, 2023. View meeting information here.
Initial Response: PNM
Thanks for the question.
We have thought about that.
The first thing that we're doing in terms of ELCC at least is we're using what's known as a UCAP or unforced capacity metric when putting the capacity contribution for thermal resources into the planning model. So, we're not just saying that they get a 100 percent nameplate, but it's something less based on either historic expected forced outage rate data or forecasted data for new units.
We've gone through and looked at data from NERC (North American Electric Reliability Corporation) GADS (Generating Availability Data Standard) data. We've gone back and reviewed that and done some analysis regarding the question: "Can we determine for PMM's units any type of weather dependency outages for extreme temperatures?" And the answer so far is no.
Back in 2011, there was a pretty bad cold snap that did cause some things to happen on PNM’s system, and PNM at that point put together a plan to weatherize a lot of the plants. And so, in recent years, when we look at what's going on with our plant availability, we don't see any data-driven analysis that shows correlation between weather and outages on our fleet.
We also did a supply-side resiliency study that asked the question, “Well, what happens if you did have correlated outages, say, with fuel supply disruptions or other impacts to different elements of the system?” And so, we would plan on--we talked about this on May 4 [2023] - building into our overall framework some resiliency analysis.
Some things we're looking to get out of that resiliency study are: a) given the results, what would the stakeholders recommend, as well as b) what would our customers be willing to bear in terms of the increased costs associated with the necessary investments in resiliency refinements to the system versus the probability of outages and how much the cost of those outages would be.
So, we do have that type of framework in mind, but as far as coming up with ELCCs for the existing system--for gas units, mainly, I think what you're getting at--we don't see anything in the data that would suggest the necessity of that analysis.
Finally, if we look at where the risks are on our system, predominately before we get very far out in the future, it's mainly summer net load risk. The majority of the types of correlated, weather-dependent outages or common mode failures [I think you're referring to] are associated with winter risk that we're just not seeing on our system.
I know there was a study done for Texas as well as for PJM, but the risks to our system are just not manifesting in the same way.
Pine Gate Renewables continued.
Appreciate that.
Asked by Form Energy on May 11, 2023. View meeting information here.
Initial Response: PNM
Thank you for the question. Another great question.
When we're doing the ELCCs, and the reserve margin calibrations [SERVM modeling], that is actually five-minute modeling for an entire year across multiple weather years and multiple forced outages, load forecast uncertainties, et cetera. So, that is full year modeling deep down to the five-minute level for establishing those pieces.
For the capacity expansion [EnCompass modeling], after we put the ELCCs and reserve margin into the capacity expansion model, for some of the runs that will be looked at, the capacity expansion model will be limited to, say, a typical on-peak and off-peak day per month for each month of the 20-year planning horizon.
We understand that, for example, with long duration storage, that may not allow the model to fully capture the benefits of long duration storage. So, for those long duration storage aspects, what we'll have to do is force into the model the long duration storage, drop down into a middle step that's not fully described here but is described in the presentation we made on July 27 [2022] as part of the PNM Public Advisory Process (link: https://www.pnmforwardtogether...).
A quick summary of the intermediary step: Rather than doing, say, rolling weeks for production cost simulations, we'll force 18 months of data into memory at once on an hourly basis. So, that way the model has kind of perfect foresight in order to capture the seasonal build up, flow up, flow down of energy in and out of the long duration storage asset. So, we can get kind of an optimal use case for that.
We can then build that operation back into the larger capacity expansion optimization to make sure that use case is then reflected when making decisions around additional resources in the rest of the portfolio for [the entire 20-year timeframe].
And then, once the optimal portfolio is determined, we'll drop down into more detailed production costing, where we force even more granularity, and even more constraints on, say, minimum uptime, minimum downtime, and other binary variables.
So, we recognize that for long duration storage, whether it's iron air core, whether it's pumped hydro, hydrogen, other such things that require that seasonal buildup, there has to be an intermediary step where we're putting at least a year, more likely 18 months, of data into memory at once in order to make sure they were able to have the model see and understand the needs for that seasonal build up and draw down over time.
Form Energy continued.
Got it. That was really helpful. Thanks for walking through that and just a quick follow up:
Is there room for us to kind of engage on these types of questions and approaches as part of this IRP stakeholder process versus kind of just suggesting the scenarios and futures for capacity expansion modeling?
PNM continued.
We're absolutely open to feedback through the modeling working group and subgroups.
I think that whether or not we could adapt a framework to incorporate changes would depend on how we can do testing of that change to the framework, get comfortable with it, and believe that we can incorporate those changes and still meet our filing dates.
Form Energy continued.
Got it, yes.
Gridworks continued.
So let me jump in.
Yes, people have had suggestions on adjusting a framework that might be better suited to where we're headed in the long term. Those are entirely welcome and this modeling engagement plan that we're going to distribute to folks will talk about that. We are going to collect those ideas.
The utility is not obligated to make changes to their framework at this point because there's quite a bit of validation and verification that would have to be done to any new framework, but we are collecting those because that's part of input to the [Public Regulation] Commission about moving ahead in the future.
So, thanks for that idea. We will be collecting those ideas and there will be opportunities to discuss those.
Form Energy continued.
Okay.
Asked by Mitsubishi Power on May 11, 2023. View meeting information here.
PNM Response:
With regard to the candidate resources, we're open to modeling others.
For what we've looked at on our system, we believe that aeroderivatives with the vast ramping capability will provide the most value to our system, especially being able to move towards our renewable goals and help chase renewables and a lot of those renewable integrations where the combustion turbines don't necessarily have the same start time, minimum load characteristics, and ramping capabilities as aeroderivatives.
We're not saying that we would limit ourselves to that. And we could look at some others. I often think that when the rubber meets the road, the IRP does not determine what resources we are adding; it gives us general trends.
And to the extent that there are resources with relatively similar characteristics, when we go to an RFP, we're not going to say we're doing an RFP for aeroderivatives; we would be saying we're doing an RFP for resources. And to the extent there are other resources that help meet those needs with similar operating characteristics, we would then make those decisions on a cost basis.
Asked by Mitsubishi Power on May 11, 2023. View meeting information here.
Initial response: PNM
So, EnCompass does have the ability to make the problem size as big or as small as you want, but putting 20 years of 8760 data in the memory just won't solve, at least not on our machines.
Mitsubishi Power continued.
You can do one year and then roll over and then carry forward one year.
PNM continued.
If you were to do one year at a time, you wouldn't have the ability to understand how 2040 is affected by capacity decisions in 2025.
So we need to have a planning problem that has a multi-year horizon when making those capacity expansion decisions. And I would say, regardless of whether you could put the full 20 years in at 8760 data, if it's still done in a deterministic fashion, you can't get away from having ELCCs.
The end-all solution in PNM's mind would be having a capacity expansion that had a stochastic sub-problem that incorporated loss of load probability metrics within the production costing aspect that would be feeding back into the capacity expansion problem. But that's just well out of the realms of current computing power and models.
But if we can't put a stochastic production cost in, even just doing a single deterministic run on capacity expansion, even if you could fit the 8760 for 20 years in, it would not give you enough detail in order to assess what the reliability contributions of resources were.
Asked by New Mexico State University on May 11, 2023. View meeting information here.
Initial Response: PNM
So, our intention is to share results along the way. You just mentioned that modeling is an iterative process. We are [going through that iterative modeling process] here internally. Our goal is to be able to share all of the results on June 15. To the extent that we can't get to all of the results, we will share what we have and continue to provide updates to the modeling subgroup. But I don't think that necessarily is a prerequisite for the subgroup to come up with what they think the best ideas [for modeling run requests] are as well.
New Mexico State University continued.
Yes, I would see it as two phases. I'm sure that the subgroup can come up with some ideas prior to your presentation, but then your presentation will probably inspire need for a few more after that.
PNM continued.
Okay, absolutely.
Asked by New Mexico State University on May 11, 2023. View meeting information here.
PNM Response:
Yes, that's on our July 27, 2022, presentation (link: https://www.pnmforwardtogether...)
It's mostly in pictorial form and it's the same model and data set that was used for all the other models, just using a different optimization window.
Asked by New Mexico State University on May 11, 2023. View meeting information here.
PNM Response:
Yes, that is the assumption we are making. In our modeling, in the cases in which hydrogen is assumed to come from a pipeline, we assume it is 100% green. Our cost estimates for hydrogen in those cases reflect this assumption.
In the cases in which we create hydrogen using electrolysis, that hydrogen is also 100% green: the model must build enough renewable resources to supply an electrolyzer with enough power to create the hydrogen that is combusted.
Asked by NM RETA on May 11, 2023. View meeting information here.
PNM Response:
Yes, we certainly can take a look at that.
I [would ask you to go back and have a look at] our January 17 [2023] presentation on our IRP website. There's a lot of more detailed presentation materials there on the synergistic effects of ELCCs that we were capturing using our ELCC surface tool. We're not just doing marginal independent ELCCs but we are looking for that portfolio synergistic effect.
Asked by Western Resource Advocates on May 11, 2023. View meeting information here.
Initial Response: PNM
Sure, thanks, appreciate the question.
So, when we're setting this up in step zero (we've got the box around SERVM there), we don't just model PNM in our reliability modeling. We don't just model the BA [Balancing Area], but we also model at least one tie line away.
So, we're modeling all the generating units in Arizona. We're modeling all the generating units in New Mexico. We're modeling all the generating units for PSCo and SPS and some of the neighboring utilities, as well as modeling a sink for some of the energy that Arizona would be selling into California --because we can't assume that all of the excess energy that's in Arizona would come to PNM.
And so we model all of these things and we then take a look at how many imports are coming into PNM, and we compare that [level of imports] to what we've experienced during times of extreme constraints.
One of the things that we've done within the model is say that during certain periods of time we're not going to accept the model generating so many imports because it's not something that our traders or our balancing area authority has seen when we get into these extreme conditions.
So, in the top 15 percent of gross load hours, we'll put a distribution on the ability to import into the PNM BA: between 200 and 300 megawatts. And then we get into the top [20 percent of load hours that occur between hours 19-22 during June-August], we drop that down to 50 megawatts. This limit is mainly tied to the extreme conditions in 2020 with the rolling blackouts in California, during which there were time periods where we had open call offers on the market to try to import power--for $1,500 and $2,000 per megawatt hour we were not able to get more than 25 to 50 megawatts.
So, rather than put ourselves at risk by saying, “well, we expect to count on more power during times of extreme constraint," we put that as a limitation in our model. Then, when we're calibrating to that 0.1 LOLE and reserve margin requirement, we're assuming that the perfect capacity needs that we would have to add within the PNM BA cannot be met by market imports, other than that 50-300 megawatts that would be allowable during those high load periods.
So then, when we set those requirements and then calibrate the LOLE standard to a PRM, we are implicitly assuming that you can import to those limits, because we're reducing the overall level of internal capacity requirements that we would have [if PNM had no access to markets at all] by the assumed level of imports.
In addition, we don't allow interactions with the market during the capacity expansion model, but we do have an economic market that we allow the units to interact with in the production cost modeling. That way, after we've designed a system that's best suited for serving PNM retail load, we do introduce the potential for additional benefits (that our customers would ultimately realize) from making certain off-system sales or economy purchases from the market, without overly speculating on the availability of imported power during peak periods.
Because we don't want to build to sell, right? We just want to build to serve load and then assess what additional benefits there might be for different portfolios from limited economic interactions with the market.
Does that answer your question?
Western Resource Advocates continued.
Yes, and two follow-up questions.
One: Do you have an incentive program for off-system sales?
PNM continued.
No. One hundred percent of our off-system sales, margins, are passed through to our customers through our fuel clause.
Western Resource Advocates continued.
My question was trying to get at: in this whole modeling process, [what are] the benefits of interaction with western wholesale markets?
So, the general question is: In this whole modeling process in the IRP process, to what extent are you reflecting the benefits of participation in non-PNM balancing area market?
So, I think you answered that.
PNM continued.
Yes, and we're reflecting them through some of the economic transactions and the reduction of the PRM or the calibration of the loss of load expectation (LOLE) while we consider some imports as a reduction to the amount of internal resources that we would need to carry.
So, that is a benefit.
With WRAP (Western Resource Adequacy Program) or with more fully designed western markets in the future that would have kind of a coincident planning mechanism that could further reduce our ability to carry resources internally or allow a more efficient interaction with the market for economy transactions, we'll just have to wait and see how that develops.
But that's certainly something we need to keep an eye on.
Western Resource Advocates continued.
So, that's not being incorporated into outer years in the IRP planning. So, a more active participation in wholesale markets. So, what you would model in 2025 [regarding markets] is the same as what you're modeling in 2035.
PNM continued.
That's correct.
Asked by Advanced Energy United on July 27, 2023. View meeting information here.
PNM Response:
All portfolios are designed to meet a baseline Planning Reserve Margin (PRM) (calibrated to a 0.1 LOLE target); however, as we have discussed previously, PRM alone is insufficient to guarantee a reliable system. As a part of Phase 1-2 modeling, we performed a reliability check on all portfolios – see slides 10-12 of PNM modeling results update presentation. When these portfolios were evaluated under a deterministic extreme weather load case, we did not find that any portfolio had unserved energy outside the range of outcomes considered reasonable for a reliable portfolio. Further, there was not enough differentiation in this deterministic approach to justify the weighting we originally contemplated.
As a part of Phase 3, we will conduct detailed reliability modeling via SERVM. Additionally, we plan to conduct resiliency studies with the Most Cost Effective Portfolios (MCEPs) and we will give these results significant weighting when evaluating Phase 3 portfolio scores.
Asked by CSOL Power on July 27, 2023. View meeting information here.
PNM Response:
Carbon emissions reflect those that result from the combustion of fossil fuels for electricity generation to serve PNM retail load.
Our modeling is consistent with the emissions requirements laid out in the New Mexico Energy Transition Act. This prescribes carbon intensity levels for emissions that result from electric power generation, i.e., stack emissions.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
PNM will model a variety of sensitivities in Phase 3 scenarios, including those that incorporate high and low natural gas and market prices. Sensitivities can be found on slides 21 and 30 of PNM’s modeling results update presentation.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
PNM has incorporated Investment Tax Credits for all storage and Carbon Capture technologies, and Production Tax Credits for renewable, nuclear, and hydrogen production.
Asked by NM RETA on July 27, 2023. View meeting information here.
PNM Response:
The Present Value of Revenue Requirement for each portfolio (presented on slide 14) reflects the portfolio cost over the study period. The cost for the “base technologies only” portfolio is highest because it requires the greatest amount of installed capacity (due to ELCC effects and the lack of long-duration storage or new dispatchable resources in that scenario).
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
The “Thermal – CT” scenario includes base technologies, and allows for the addition of Combustion Turbines capable of burning hydrogen in 2040 and beyond (these incur a hydrogen conversion cost in 2040). The hydrogen burned in these CTs in 2040 and beyond is assumed to be delivered to the PNM system (as opposed to being created vis electrolysis using designated renewables and stored on site, as in the Green Hydrogen scenario).
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
In the Thermal-CT scenario, all CTs remaining online in 2040 and beyond incur a conversion cost that reflects the necessary upgrades to enable 100% hydrogen combustion. The cost of delivered hydrogen ranges $20-21/MMBtu ($2025, base assumption) in 2040-2042.
In the Green Hydrogen scenario, costs associated with hydrogen production and combustion include hydrogen-ready CTs, electrolyzers (and associated PTCs for hydrogen production), solar resources to supply the electrolyzers (and associated PTCs), and hydrogen storage (above-ground).
Asked by ICF International on July 27, 2023. View meeting information here.
PNM Response:
All of our modeling is based on our current understanding of the IRA and assumes the hydrogen PTC expires in 2032. Based on these assumptions, we don’t see much hydrogen production and combustion once the hydrogen PTC expires. While the Green Hydrogen case is the lowest cost over the study horizon (2023-2042), cost advantages are directly attributable to PTC value (including PTCs for wind and solar).
However, the extent of the IRA impact on the Green hydrogen industry remains to be seen. The PTC is incredibly valuable and is likely to spur investments in green hydrogen production that provide for technology improvements and efficiency gains and could eventually result in a hydrogen economy. These types of developments may decrease the cost of initial investments in green hydrogen on a broader scale and help future project economics, particularly in places where there is a strong renewable resource. Extension of the hydrogen PTC can be expected to incentivize hydrogen investments further into the future.
Asked by Western Resource Advocates on July 27, 2023. View meeting information here.
PNM Response:
The IRP is not filed with testimony, it is a report that is either accepted or sent back for revision based upon whether the IRP Statement of Need and Action Plan comply with the policies and procedures of the IRP rule (NMAC 17.7.3.9).
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
a) Phase 3 will incorporate the Base technologies + LDES and Base technologies + LDES + CT scenarios also modeled in Phase 2 – there is no difference in the technologies available for the model to optimize in these scenarios between Phase 2 and Phase 3. However, when modeled under different sensitivities in Phase 3, these scenarios might produce different portfolios/resource mixes than in the Current Trends and Policy (CT&P) case modeled in Phase 2.
b) Per Gridworks, the deadline for submitting modeling run requests was May 26.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
These scenarios were specifically requested by a stakeholder. The first assumes PNM exits its share of Four Corners in 2027, and the Valencia PPA is extended through 2039. The second assumes PNM exits its share of Four Corners in 2027, the Valencia PPA is extended through 2039, and Reeves continues to operate through 2039. In both of these requested scenarios, Valencia and Reeves extensions do not incur any costs – they are free (as agreed to by stakeholders in the modeling request meetings).
In the Base Technologies only scenario, Valencia PPA expires in 2028 and Reeves retires in 2031.
In 2040, the stakeholder requested scenarios produce the same portfolio as in the Base Technologies only scenario because Valencia and Reeves do not operate past 2039.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
All available information can be found in the data sets posted to the Venue site. Because this is not an RFP evaluation, we will not be posting project-specific information, such as for a Valencia extension.
Asked by a member of the public, on July 27, 2023. View meeting information here.
PNM Response:
The IRP rule requires evaluation of portfolio costs over a planning horizon of at least 20 years, – we have done this with the PVRR metric. Bill impacts would only look at a single year and may not adequately capture long-term tradeoffs in resource choices. Furthermore, transforming PVRR into bill impacts would require assumptions around cost of service, cost allocation, ownership structures, etc. – this is beyond the scope of the IRP.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
In the Valencia and Valencia & Reeves extension scenarios (stakeholder requests) there are no additions of thermal resources (and no hydrogen combustion) – the only new resource types available to the model are wind, solar, and 4-hr lithium-ion storage (the same as in the Base Technologies only scenario). However, one can glean from the Thermal - CT analysis whether gas fired generation is cost effective when Reeves or Valencia would come out of the portfolio. If similar amount of new gas is added at those times, one can conclude that whether new gas, or an extension of those units, is cost effective and the specific choice would come down to RFP bids in an RFP evaluation.
These two stakeholder-requested scenarios differ from the Base Technologies scenario in only two ways:
- PNM exits its share of Four Corners in 2027 (as opposed to in 2031)
- Either Valencia (in the Valencia extension scenario), or Valencia and Reeves (in the Valencia and Reeves extension scenario) extend through 2039 at no additional cost (as opposed to the Valencia PPA ending in 2028 and Reeves retiring in 2031)
The stakeholder requested scenarios differ from the Thermal-CT scenario in three ways:
- PNM exits its share of Four Corners in 2027 (as opposed to in 2031)
- Either Valencia (in the Valencia extension scenario), or Valencia and Reeves (in the Valencia and Reeves extension scenario) extend through 2039 at no additional cost (as opposed to the Valencia PPA ending in 2028 and Reeves retiring in 2031)
- Options for new resource additions include only wind, solar, and 4-hr lithium-ion storage (as opposed to wind, solar, 4-hr lithium-ion storage, and generic Combustion Turbines that will be converted to burn hydrogen in 2040)
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
We think it’s important to consider the extent to which some portfolios can provide for earlier reduction in carbon emissions. Given that all portfolios meet ETA requirements, the NPV CO2 metric receives an overall weight of 15% in the scoring methodology – far below the 70% weight given to portfolio cost (as measured by PVRR).
Asked by Western Resource Advocates on July 27, 2023. View meeting information here.
PNM Response:
Stakeholders were asked to submit their top five factors (IRP evaluation criteria priorities) and rank by importance. PNM has proposed using the results of the factor survey to create a stakeholder-derived scoring matrix. Ultimately, we’d like to compare Phase 1-2 results scored using PNM’s scoring matrix with those scored using the stakeholder matrix. The overall goal would be to understand where PNM and stakeholders align in terms of evaluation criteria and level of importance.
Asked by Western Resource Advocates on July 27, 2023. View meeting information here.
PNM Response:
Final modeling results will incorporate 2026 RFP resources and associated costs. The results presented on July 27th do not reflect incorporation of these resources into IRP modeling.
Ultimately, the RFP resources will be the same in all portfolios so addition of these resources is not expected to materially change the comparison across portfolios.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
All available information can be found in the data sets posted to the Venue site. Because this is not an RFP evaluation, we will not be posting project-specific information.
Asked by Western Resource Advocates on July 27, 2023. View meeting information here.
PNM Response:
New CTs in the Thermal-CT case are assumed to burn natural gas through 2039. In 2040 they incur a conversion cost and are assumed to burn 100% hydrogen thereafter. Generic LM6000s have a 40-year operating life and depreciation period. This is appropriate because it is reasonable to assume that these resources will be able to utilize a non-carbon-emitting fuel (hydrogen or other) and operate for the entire 40-year life.
Asked by the New Mexico PRC on July 27, 2023. View meeting information here.
PNM Response:
Yes, we've incorporated new ELCCs in the EnCompass modeling that do account for diversity benefits between solar and storage. We found that there was not a lot of correlation between wind and the other two. So, yes, those diversity benefits are captured.
Asked by Western Resource Advocates on July 27, 2023. View meeting information here.
PNM Response:
Yes, that's the idea. And we could talk about a different number. It doesn't have to be 10 percent. That's what we've used for this round of results.
Western Resource Advocates continued.
I understand that approach.
Asked by New Mexico State University on July 27, 2023. View meeting information here.
PNM Response:
For each hour in each weather year, SERVM does a Monte Carlo simulation, a random draw on the load, the forced outage rates of resources, and also on the production profiles from solar and wind.
Those are the things that are changing [in] each of those 10 simulations.
NM State University continued.
So, what's the deterministic part?
PNM continued.
It is not deterministic. The SERVM model is not a deterministic model. It's a stochastic model. EnCompass is a deterministic model.
NM State University continued.
Maybe I am misreading the earlier slide. I'll go take a look.
PNM continued.
When we're modeling an extreme weather case, that is a deterministic evaluation, and we're trying to [understand the difference between that and] our base [(P50 load)] case.
[The extreme weather load forecast and P50 load forecast] are two deterministic forecasts that we have in EnCompass.
What we're trying to do is get a sense of a reliable portfolio from SERVM: [what is] the range of unserved energy [produced across SERVM simulations for an extreme weather year] … and how that compares to the differential we're seeing from a deterministic point of view in EnCompass.
So, we're trying to make that leap to see if EnCompass is really going to give us a reliable portfolio or not. That's the slide [Slide 12] that is up on the screen now.
We think that the comparison is between [the extreme weather case run in EnCompass and] a single SERVM simulation, right? One of these dots versus the deterministic EnCompass case.
NM State University continued.
How do you choose which one of the SERVM you're comparing against?
PNM continued.
When we look at all these dots, we say, “Okay, a single year, a single run could result in up to 1,500 megawatt hours of unserved energy for an extreme weather year like 2011.” So, we just figured if EnCompass spits out unserved energy somewhere in this range of dots we circled here, we can't say that’s not a reliable portfolio because that one case is in the range of things that resulted from SERVM simulations for an extreme [weather year].
NM State University continued.
Okay, that makes sense. You’re saying It fell within the realm of what we think are the possibilities.
PNM continued.
Exactly, yes.
We're trying to focus on an extreme weather year here [Slide 12] and that's exactly what we're trying to do in EnCompass. What SERVM is telling us is when we look at an extreme weather year, here’s how much EUE we’re having, like in a Monte Carlo kind of stochastic view, here's the range of unserved energy we're seeing. And [in] just one deterministic [extreme weather] case in EnCompass, the EUE is falling within that range.
And so, we think that we have a good case to say that each of these portfolios, even from the low end to the high end of EnCompass results [Slide 11], all [unserved energy that resulted from the extreme weather case falls within a reasonable range, and so we cannot say that these portfolios are producing results that lead us to believe they would be unreliable].
Recall that once we get to Phase Three, we're going to run all of these portfolios through SERVM, at least in the Current Trends & Policy case, so we'll get a much better, detailed result from that analysis when we get there.
NM State University continued.
Again, I misunderstood where you used the deterministic earlier in your slides. There might be something that would make it clear.
PNM continued.
Thank you.
Asked by a stakeholder on March 28, 2023. View meeting information here.
Gridworks Response:
We're working to try to make sure that we have information both on the Gridworks website and on the PNM website, so you could go to either place.
We understand that this transition is going to be a little challenging communication wise, but we, again, are very pleased with the partnership that we have with PNM and the communications back and forth to make sure all of you learn what's next and how to reach us--a high priority for both Gridworks and for PNM, so we'll continue to try to get information in multiple locations. But we'll try to streamline the registration process.
Asked by a member of the public on March 28, 2023. View meeting information here.
Gridworks Response:
That's not directly related to [today’s presentation] but it is important.
Additional (Previous) PNM Responses to Member of the Public.
Member of the Public.
What is the relationship between PNM and PNMR and what is the role of each in the IRP process and implementation?
PNM Response.
PNM is a wholly owned subsidiary of PNM Resources. PNM is a regulated utility subject to the rules and procedures of the New Mexico Public Regulation Commission (NMPRC). The IRP rule applies only to PNM, not PNM Resources. PNM Resources is a publicly traded company not directly subject to the regulatory oversight of the NMPRC. PNM is responsible for developing the IRP and must make filings and gain approval from the NMPRC to acquire any resources subject to the NMPRC’s Certificate of Convenience and Necessity (“CCN”), Power Purchase Agreement (“PPA”), and other applicable rules.
Member of the Public.
What PNMR businesses are within or outside the IRP process? What percentage of PNMR are in each of these categories?
PNM Response.
The only PNMR business subject to the NMPRC IRP rule is PNM. Member of the Public Does anything in the non-regulated sector impact on PNM’s planning and/or operations? If so, how? PNM Response Many things in unregulated sectors impact PNM’s planning and operations, such as the price for new resources, the cost of natural gas, the cost of capital, regional markets and other factors – all of which are not regulated by the NMPRC. Most of the fundamental drivers in the planning and operations process are things beyond PNM’s and the NMPRC’s direct control. PNM plans within uncertain environments to best meet its customer’s needs. PNM’s rates, procurements and operations are regulated by the NMPRC.
Member of the Public.
How do unregulated activities relate to the IRP process?
PNM Response.
See response to the previous question.
Member of the Public.
What are the PRC’s objectives and expectations for the IRP process?
PNM Response.
The NMPRC IRP rule provides the objectives of the IRP process.
Member of the Public.
In the revised IRP rule 17.7.3.1 NMAC of 10/27/2022, which parts are new, and which carry over from before? A table showing the changes could be helpful.
PNM Response.
Please find attached Exhibit B which is a redline of the previous rule to the new rule which was filed in the IRP Rulemaking Docket, Case No. 21-00128-UT.
Member of the Public.
Where are the stakeholders defined in the new Rule?
PNM Response.
Stakeholder is not a defined term in 17.7.3 NMAC.
Member of the Public.
How do the commission or PNM know when enough varied stakeholders are participating to meet requirements?
PNM Response.
The facilitated stakeholder process that is currently being conducted by Gridworks has been sent to a very broad group. Facilitated stakeholder process is defined in 17.7.3.7(F)(1) NMAC.
Member of the Public.
What happens if no stakeholders can be enlisted from a given key sector?
PNM Response.
The Commission determined in its rulemaking that the Commission-defined facilitated stakeholder process is appropriate to receive public input to the IRP.
Member of the Public.
How does the Statement of Need relate to PNM’s business plan and operations?
PNM Response.
The Statement of Need defines requirements that PNM must meet in the future; however, before finalizing agreements with any new resources, PNM must seek approval from the NMPRC through filings for a CCN, approval of a PPA or other applicable approvals. Therefore, the Statement of Need outlines a high-level roadmap for future procurements and investments by PNM, but actual outcomes may vary when specific market bids are sought to inform procurement analyses and filings.
Member of the Public.
Is the Independent Monitor for RFPs a new element under 17.7.3?
PNM Response.
Yes.
Member of the Public.
Under 17.7.3.12(F)(4) NMAC, What is meant by “resources be able to operate under automatic dispatch control”? PNM Response Resources that have Automatic Generation Control (AGC) can follow a dispatch signal sent by the remote system operator to vary its output to a desired set point.
Asked by a stakeholder on March 28, 2023. View meeting information here.
Gridworks Response:
One of the things that that we're going to be working through is whether the modeling software is available to you as stakeholders, or whether we're going to work with PNM and be able to talk about PNM’s assumptions and how their modeling is done.
Asked by a stakeholder on March 28, 2023. View meeting information here.
Gridworks Response:
Yes, it is recorded, and everyone will have access to it. It will be posted, so it will be available to anybody.
Asked by a stakeholder on March 28, 2023. View meeting information here.
Gridworks Response:
Obviously, the assumptions that go into modeling are critically important and some of those may be confidential; some may not. And so, we're going to have to work through what all can be provided to stakeholders because the basis for what comes out of the model is the assumptions that you put into the model.
Asked by Pine Gate Renewables on March 28, 2023. View meeting information here.
Gridworks Response:
Thank you. That's super helpful.
Asked by Synapse Energy Economics on March 28, 2023. View meeting information here.
Gridworks Response:
Good suggestion. Thank you.
Asked by NM Area on March 28, 2023. View meeting information here.
Initial Response: Gridworks
Thanks.
PNM continued.
For all those folks who are inquiring about input assumptions and other such things along those lines, we would encourage you to please visit the PNM IRP website. There have been 15 meetings previous to this where we've discussed a whole host of different modeling assumptions, techniques, frameworks, et cetera, so a lot of that information is out there. If you have not been following the process so far--I know we're transitioning to the facilitated part of this process--but there has been a lot of work done and reviewing all those materials will get you a head start in terms of trying to get more in line with what we've been doing thus far in terms of modeling, inputs, assumptions, frameworks, techniques, et cetera. I appreciate NM AREA’s point. We'll have to talk about all that because, as we've discussed, there comes a point where we have to all be working with a consistent set of data. To the extent there's request for updates to the data--who knows what can be accommodated-- sending out multiple different versions of databases becomes very problematic.
Asked by a stakeholder on March 28, 2023. View meeting information here.
Initial Response: PNM
Portfolio modeling is still ongoing and will be part of this process of getting input in terms of different scenarios or sensitivities that maybe we have not considered that you would like us to do, Now, there has been a lot of modeling already done in terms of setting up the various inputs. We've already done modeling to do the load forecast. We’ve got 14 different load forecasts. We've already done modeling to assess ELCC curves and reserve requirements and energy efficiency bundles and all of these other things.
So, the modeling started to develop all of the inputs over a year ago. We're at a point now where we need to start figuring out if there anything else we need to be looking at as far as inputs, because time is of the essence in order to try to modify those things, or are we just going to be locking down the input assumptions at this point?
We're really trying to figure out are there different modeling requests that we need to accommodate, based off the existing information that we've already put together.
Gridworks continued.
Thank you.
One thing to point out to the group is that, because of the timing of the legislation, we've had to start this process after PNM has already initiated their process, as was mentioned.
So, we're trying to navigate how to serve the [Public Regulation] Commission best with its request and its new legislation while we're in the midst of this process,
Asked by New Mexico State University on March 28, 2023. View meeting information here.
Gridworks Response:
Thank you for the input on that. Let us look at that and get back to you.
Asked by Office of Senator Heinrich on March 28, 2023. View meeting information here.
PNM Response:
Sure, we can put that link into the chat or send it out via email. It's generally the website we've got all the presentation materials from the previous 15 meetings that we've done. We’re putting it in right now.
Gridworks continued.
We will also put it in the meeting summary that we’ll send out—both the like to the recording for this meeting and resources where there's information--the PNM presentations from past as well, as the this presentation, et cetera. So, we will make sure that those are referred to and linked in our meeting summary.
Asked by a member of the public on May 18, 2023. View meeting information here.
Initial Response: Gridworks
Thank you. Very helpful.
Working Group continued.
On the end of life and education portion, that is addressed in 2.2 and 2.3 of the [draft Statement of Need] document, so it is there.
Asked by a member of the public on May 18, 2023. View meeting information here.
Initial Response: Gridworks
Thank you. Very helpful.
Working Group continued.
On the end of life and education portion, that is addressed in 2.2 and 2.3 of the document, so it is there.
Asked by InterWest Energy Alliance on May 18, 2023. View meeting information here.
Gridworks Response:
Thank you.
Asked by CSol Power on May 18, 2023. View meeting information here.
Gridworks Response:
Thank you for that.
Asked by ENMRD on May 18, 2023. View meeting information here.
Initial Response: Gridworks
For the benefit of all our stakeholders, will you please define renewable natural gas?
ENMRD continued.
Any methane that's captured from a waste product: effectively it could be from a landfill or from a digester or a wastewater treatment plant. But the ETA [Energy Transition Act], as everybody looks at it, there was a last-minute amendment to that on the zero-carbon resource standard, mainly for the Albuquerque wastewater treatment plant that generates power with their bio gas. It doesn't stipulate that it has to be the gas produced on site and burned on site; it just says you must capture X amount of methane and then burn that. So, the zero-carbon resource doesn't mean zero carbon emissions. It means it's offset by the methane that's captured somewhere else. I think that is something that needs to be looked at because it would be a very easy fuel switch and we have massive feedlots that are emitting methane right now that have no place for that methane because it's not valued as a resource.
Asked by NMPRC on May 18, 2023. View meeting information here.
Gridworks Response:
So, our next steps are going to be to start to fill out this outline. And so, if they're the entity that has the appropriate information, the answer would be yes, that that information would come forward.
Asked by NMPRC on May 18, 2023. View meeting information here.
Gridworks Response:
Yes, so they would bring forward their DSM portion. The working group could also, in its preferred section, ask questions or bring in information that it would like to see studied that's beyond or different than what PNM has.
Asked by CSol Power on May 18, 2023. View meeting information here.
Initial Response: Gridworks
Yes, and I think someone put in the chat that geothermal is in a list of resources.
CSol Power continued.
When I looked at this outline and I looked at PNM’s list of resources I did not see geothermal, but I could be wrong about that. Geothermal is in Lordsburg. It's a very small plant … but it is something that could be developed in New Mexico.
Gridworks continued.
Yes, I mean, in the list of resources that PNM is going to consider going forward, I did not see geothermal. Someone in the chat said it wasn't there.
CSOL Power continued.
No [it’s not in the list of PNM resources going forward] because it's already part of their assets. Gridworks continued. I think it could be. ENMRD mentioned in the chat geothermal always was in the current mix.
ENMRD continued.
Yes, they have it in their current PPA’s.
Gridworks continued.
Yes, great. Okay.
Asked by Lincoln County LANRAC on May 18, 2023. View meeting information here.
Gridworks Response:
Thank you. We would encourage you, if there is a place in the outline that you think that is most appropriate, if you want to send verbiage to us, that would be great.
Asked by SWEEP on May 18, 2023. View meeting information here.
Asked by InterWest Energy Alliance on June 1, 2023. View meeting information here.
Gridworks Response:
Great. Thank you. We'll be sure that all those materials, those four documents that we received from InterWest, are loaded on our Gridworks website. We'll be sure that material is brought to the benefit of the working group on Statement of Need, so thanks for reminding us about that.
Asked by NM AREA on June 1, 2023. View meeting information here.
Initial Response: PNM
[Regarding Valencia]. we are not going to put a specific RFP bid into the IRP.
NM AREA continued.
I guess my thought on that is that if you retire [it], then the model has a hole. So I don't know how to do it in the modeling, but make it so that there's not a hole that it's filling, right? Either just put in a generic gas plant or whatever.
Working Group continued.
That's what [PNM is] doing. right?
NM AREA continued.
You don't have to model the RFP, Just make it so that the model's not filling in for a hole.
PNM continued.
So, that's why we said we think that's one of those where we need to sit down and talk about the implications and what we're trying to accomplish there. If you have a scenario where Valencia comes out, and it gets replaced by similar sized gas plant, there's no way you could come to any other conclusion than an extension of Valencia is certainly a possibility, but until we get to an RFP analysis, we're comparing it to another set of resources that would compete against. Putting in just a single RFP bid against generic data doesn't provide useful price information.
NM AREA continued.
[I was just asking about the ones you are already doing.]
Working Group continued.
We included them because they're not, I believe, precisely what PNM is already going to do, but they were asked by several stakeholders. That's why we included them in the list. Several people asked about Valencia. Several people asked about demand response.
Asked by NM AREA on June 1, 2023. View meeting information here.
PNM Response:
The answer is yes, meaning that the confidential data and the data dumps will have all of the hourly loads in hourly market prices and other things like that. It's just going to be in a model format, so [it’ll] take a little bit of working from the stakeholders to go and understand that format and pull the information they want out. If you want to have the most granular set of information, if that's meaningful to what you need to do in order to put together a model request or something else, that's where it will be. But [we’re] not going to go through the process of taking that data dump and separating it apart into specific elements. It's already there. You just have to look at how to use it.
Asked by a member of the public on June 15, 2023. View meeting information here.
Initial Response: Gridworks
Thank you. I know you have asked some folks for input and haven't gotten it. We may be able to address this in a introduction to the Statement of Need to be able to call out that education of the public about what's happening around energy generation development is important. So, I think we can pull that out and make that more important or stand out more. Thank you for the comment.
Member of the Public continued.
You're welcome.
Asked by Office of Sen. Heinrich on June 15, 2023. View meeting information here.
Initial Response: PNM
Typically, in the IRP, we don't get down to distribution level modeling. It's done at the bulk transmission level. So, the reliability and resiliency discussions and previous IRPs have been on NERC standards, overall LOLE planning type requirements as well as operating reserves. We certainly can discuss a little bit, down to the distribution level about maybe what SAIDI, SAIFI etc. is, and the Statement of Need does call out--that we could talk about within the Statement of Need in the context of new resources or what we believe the most cost-effective portfolio will be, what additional improvements might need to be done to the transmission and distribution system. In terms of modeling down to that level. that is not something that is going to be incorporated in this IRP, though.
Office of Sen. Heinrich continued.
My comment on the reliability on the distribution level is: It may affect because PNM is vertically integrated you have all three, there may be some, with regard to the Statement of Need--in terms of what new resources are you procuring and why, and how is it going to affect ultimately reliability--I think having some mention of the reliability in terms of SAIDI, SAIFI, etc. and is that being done at a granular enough level to do a couple things. One is to ensure what circuits are poorly performing. Is it down to that granular level? I know a lot of those are reported on the entire system level. But also, the other need I noticed equity is on there. I think that's important. Number two, the public interest equity. Being able to ensure the equity/equability of the reliability of these systems. … I just think it's important to say is the reliability on the distribution system equitable and there are ways to maybe monitor for that if it's not already being done. And then from a resource perspective for this Statement of Need. is it within the scope of this? I’m not sure, but I just wanted to throw out that there might be some distribution level reliability issues that could help just overall reliability in terms of the granularity of how the data is reported, but also on equity.
Thanks.
PNM continued.
I definitely appreciate your comments and for those folks who are unaware, there is going to be a reliability workshop at the PRC [Public Regulation Commission] special open meeting tomorrow [June 16] where all three vertically integrated utilities in New Mexico are going to be talking about distribution reliability.
Asked by New Mexico State University on June 15, 2023. View meeting information here.
Gridworks Response:
So, one was modeling on the turbine technologies and it's capabilities to provide voltage support and some other things. And the other one was related to load forecasting and if energy efficiency [DER?] storage are being considered under electrification. So, thank you.
NM State University continued.
Thanks.
Asked by REIA on June 15, 2023. View meeting information here.
Initial Response: Gridworks
I would love to task [REIA] with some stuff. So, I would appreciate it if you would take a look at this and see what you think needs to be included. It's certainly an evolving area, so appreciate any thoughts you can provide to [the modeling subgroup].
NMPRC continued.
[Pointed out that] the IRP rule does refer to consideration of distribution planning.
PNM continued.
[NMPRC] is referring to in the second bullet under Statement of Need [Slide 1 of6] It does refer to expanding or modifying distribution grids as one of the things that could be considered an overall defining what the Statement of Need relative to new resources would be. So, we would want to think it about context. It's not an entire distribution planning exercise.
Gridworks continued.
Right, and as somebody mentioned earlier, this is an evolving field, right? We need to be looking in the future more at the distribution system because more of our resources are going to be on distribution.
So, we're not going to solve everything in this round. This process is going to go on. So, I think we need to address it and figure out an appropriate way to include it in the Statement of Need.
PNM continued.
Absolutely. Just in terms of the way that the models have currently been set up and what we can look at. Anything that's done at the distribution level will have to be thought of in a way where it's aggregated to bulk transmission in order for analysis, we can certainly think about ways to, to improve things going forward, but currently the modeling capabilities are separated between bulk and distribution levels.
Office of Sen Heinrich continued.
Is it possible, in addition to modeling in the IRP and in particular for this Statement of Need, to suggest that data collection and use would be beneficial in terms of distribution level reliability. I agree it's hard to model a lot of these faults that occur on the distribution system, but I'm really interested in how data can be collected at a granular enough level to help inform resources, not only distributed energy resources, but even going back to the bulk generation and transmission and, then again ... equity.
Is reliability being disproportionately or the non-liability affecting certain populations more than others? Do you think data collection and use is within the scope?
Gridworks continued.
I think this is a longer conversation and it's great that [it's been raised.] The statement of the group can consider that as part of the discussion about future actions to monitor reliability metrics at the distribution level. Let's not do the conversation now, but I think it's an important capture of an idea to put into the document.
Asked by NMPRC on June 15, 2023. View meeting information here.
Initial Response: PNM
So, we will be posting the output files for all of these cases to VENUE shortly following this meeting and anybody who's requested access to the public data will be able to go through there and get whatever they need out of it. Gridworks continued. And those inputs on nameplate and effective capacity are part of the outputs. That would be part of that data set, right?
PNM continued.
You'll be able to see for every resource both, it's nameplate capacity as well as its effective capacity, recognizing that the effective capacity of a resource changes year by year as the overall portfolio changes year by year, following those ELCC curves that we've talked about numerous times throughout these presentations, So that information is going to be specific to each scenario, which is why it's an output and not an input.
Gridworks continued.
Great. Okay. Thank you.
PNM continued.
On the input public data there were some examples of the overall ELCC surfaces that folks could kind of start to understand the interactions between the different technologies. On the outputs here you'll actually see for the given scenarios, for the given years, as the portfolios change over time what the effective capacity of those different portfolios are on a year by year and a portfolio-by-portfolio basis.
Gridworks continued.
What's your plan for posting the preliminary result?
PNM continued.
We'll have the outputs that support this presentation posted later today, along with [the information] for those people who signed the NDAs--we'll post the full confidential inputs, which will have all of the hourly data and other such things as well.
Gridworks continued.
Great, Thank you.
Asked by REIA on June 15, 2023. View meeting information here.
Initial Response: PNM
Sure. That 125 megawatts is included in all of the scenarios because it's been identified; it is a planned resource. So, we didn't show that here. We wanted to just capture here the things that the model chose from the suite of generic resources. That's not a generic resource. Similar to energy efficiency and demand response and all of the other changes that have been approved and are currently under construction. all of that's included in every scenario.
REIA continued.
Okay, thank you. Also, kind of related to that, I'm assuming you don't include in terms of generation, but you're looking at more as demand reduction, any increases in behind the meter solar.
PNM continued.
If you were to go to the load forecast presentation from December 2022, you can see specifics on behind the meter increases. But if you want a quick summary, we expect behind the meter PV additions to grow from their current levels up to almost 1,000 megawatts between residential and commercial by the time we get to the end of the planning period.
That is modeled as a load reduction in the current scenarios, but as we've also discussed, we are likely to be doing a [DRMS] type scenario where we can tie the behind the meter PV to some behind the meter batteries and see what type of offsets that may reduce utility investments by.
REIA continued.
Great. Thank you very much.
Asked by CSol Power on June 15, 2023. View meeting information here.
PNM Response:
It's all costs. It's up-front capital costs, ongoing capital expenditures, O&M, fuel, taxes, any tax credits that we would receive, authorized rate of return, all of the cost of the utility system on a revenue requirement basis are included in that present value of revenue requirements.
Gridworks continued.
And I think that the announcement that [PNM IRP] made early in this presentation, that a deeper dive presentation on these results is scheduled for next week [June 21 meeting was cancelled], is a great place for folks who have additional questions or comments and want to dig into this.
Asked by Office of Sen. Heinrich on June 15, 2023. View meeting information here.
Initial Response: PNM
So, all of these are just deterministic runs using our base, current trends, and policy inputs, and so we're going to get into uncertainty modeling as we do deeper dives and flesh out the portfolios more going forward. So right now, this is all just kind of a static deterministic run to compare the technologies against each other. We’re multiple cases of combined technologies, more complex scenarios getting into uncertainty modeling as we move forward.
Office of Sen. Heinrich continued.
I think that's the right way to do it. I just wondered if there's any preliminary assessment of, maybe without getting the actual results, just saying there are huge uncertainties in how this scenario plays out or something just to indicate, preliminarily, if that's the case.
When I read a table that has--I think it was three or four significant digits--at least my perception is that's the answer. I always caution against that: It's like, there might be huge bands that even though it's maybe five percent less than this scenario or whatever it is, the metric is, I think it's always important to just try to capture uncertainty.
PNM continued.
Yes. Thanks.
Asked by NMPRC on June 15, 2023. View meeting information here.
Initial Response: PNM
We are agnostic at this point to whether it would be a third-party asset or utility build or modeling everything using utility revenue requirements and utility cost structures in terms of when construction would actually start. So, that slide did not indicate that it was a 2032 resource. It indicated that it could have been added between 2025 and 2032, you'll see the exact result. We can't go and just build a combustion turbine without first going through an RFP process and then submitting an application with the [Public Regulation] Commission. The construction time frame for a combustion turbine is typically two and a half-ish years or so, depending, once you have all the permitting and regulatory approvals done.
NMPRC continued.
Could pop up in the Action Plan.
PNM continued.
Well, the Action Plan, being 2024 to 2026, and the fact that we already have all of our resource procurements done for 2024 and 2025, and we're currently evaluating the RFP for 2026 that will be filed before we file this case, it's unlikely that it would end up in an Action Plan.
NMPRC continued.
Okay. Great. Thank you.
Asked by a member of the public on August 31, 2023. View meeting information here.
Initial Response: Gridworks
Yes, great comment.
Working Group continued.
I would agree with that 100 percent.
PNM continued subsequently.
We [have considered] geothermal, [in response to the question from the member of the public]. We conducted an RFI (Request for Information), and we did not get any geothermal responses. We could have used some generic information, but most of what we're using in this modeling is information that was subject to a request for information that we put to market, and we did not get any geothermal market based responses. And so that's why you don't see geothermal here. [In some of our earlier meetings … we did discuss geothermal, and we did show some of the cost aspects and other things and discussed why we did not move it forward in the overall candidate resources. But it will be discussed.
Asked by NMPRC on August 31, 2023. View meeting information here.
Initial Response: Gridworks
Great. Thank you for that clarification.
PNM continued.
Just to clarify, the IRP does not procure resources and we are not seeking in the Statement of Need or Action Plan to identify specific resources for procurement. There's a separate section in the IRP Rule about procurement and RFPs, and at most what the Action Plan will do is identify that an RFP should be issued. But we will not be identifying specific procurement targets in the Statement of Need. So, just to make sure that clarification, based on NMPRC's comment, is understood. The Statement of Need will show general trends; procurements are actually done in a separate process.
Asked by Western Resource Advocates on August 31, 2023. View meeting information here.
PNM Response:
You'll get a chance to review our IRP before it's filed. We've got two more meetings coming up. It's our intention prior to the September [2023] meeting to show you the mapping of where the different elements of the stakeholder Statement of Need--if it's not going to be included in our Statement of Need, or we don't believe it will be included in our Statement of Need--that will be included elsewhere in the IRP. The goal would be for the October meeting to make sure that we have a near final Statement of Need as well as a pretty good draft of the IRP and Action Plan--all that together--because that's our last meeting before we file the IRP, unless there's a desire from Gridworks to schedule some other interim meetings throughout the holiday season. Stakeholders have the ability if they disagree then with what is filed. The purpose of this process is to try to reach agreement on the Statement of Need and the Action Plan. If there isn't agreement reached, [per Section E of the IRP Rule] we will in the IRP explain all resolved and unresolved issues. So, we have to have that list in our IRP. And then stakeholders have the ability if they disagree to include their own written comments, including their own Statement of Need or their own Action Plan. And the utility is required to have a written response to all those comments when we file our reply comments.
So, you're going to get an opportunity throughout the rest of this facilitated process to see where we are going with things to review the IRP itself. And if you feel like it hasn't gone far enough in the way you were considering, Western Resource Advocates can file its own statement and Action Plan and other comments.
Asked by a member of the public on August 31, 2023. View meeting information here.
Initial Response: Gridworks
Thank you for bringing that up. In the posted document that is included. We didn't show it on the screen today, but other considerations were part of the original document.
PNM continued.
I forgot to mention this, but we certainly do want to have, and we will have a very robust section in the IRP and the appendix discussing not just a facilitated process, but the entire Public Advisory Process, going back to April 2022. We will also include recommendations of ideas for future work or future discussion from the stakeholders, as well as PNM, as one of the items that we'll discuss in the IRP itself. So, I did want to mention that we didn't want to focus on just the Statement of Need and the IRP itself. I know that the stakeholders put a large list together of other things that should be considered going forward and we don't want to lose sight of that. And that's an important discussion for not just what did we do in this IRP but what is our roadmap going forward for potential areas of future work, future study. We'll have to prioritize it, of course. That gets to what Gridworks had said are some of their recommendation--may be starting this process much, much earlier, both in terms of modeling, and maybe some other thoughts to try to make sure that we're not trying to do all this at six, seven, or eight months when it really does take about two years to put an IRP together from when we start doing all the data gathering. If you want to talk about R&D work on modeling techniques, it's a full three-year cycle from when we start doing R&D work, gathering data, putting together everything before we file. So, it's a very long process that we do here internally and if the desire is to make sure that there is more stakeholder involvement throughout the entire process, then the process has to be understood that it is a two-to-three-year process to put together an IRP, including all of these ideas.
Gridworks continued.
From our observation of the working group and its needs, they needed to be expansive to think about the whole IRP and then it gets more collapsed down to the energy and capacity portion. That kind of goes to what's in the [IRP] Rule. And so, I think for those that weren't involved in the Statement of Need process, it may look like, well, ‘Why was all this put on paper?’ But I think the thinking process for the stakeholders was to think expansively about all the things that need to be considered in the future, and as mentioned, the policies that are guiding where we're going. It was important to capture it all in a document and then think through what should be considered in the future. So, we're kind of wandering around, and we think that we'll get to a good place. We appreciate the time of the stakeholders to be engaged and be thinking holistically about how do you screen and think about all the potential risks, futures, opportunities going forward.
Asked by New Mexico State University on August 31, 2023. View meeting information here.
Initial Response: PNM
So, the RFP that we currently have outstanding spans resources that could deliver in 2026, 2027, or 2028. At the July meeting, I gave an update on where we are with the evaluation for resources in 2026. And the resources that we are currently contracting for we have included in the IRP modeling currently, but that case has not yet been filed with the Commission and the approval of those resources is subject to the Commission’s review. So, while we are using that is our best assumption as we know here today, it is still not a certainty.
We have not completed our evaluation for resources in 2027 or 2028 out of that RFP, so all the information included in the IRP right now is based off of the generic placeholders.
But in terms of the Action Plan period, there really is not enough wiggle room given the timing it takes to evaluate an RFP and bring resources online to have things in the Action Plan that would somehow override what we would be doing in the 2027 and 2028 RFP evaluation.
The likely outcome will need to be that we will have to take a new RFP to market after we file this IRP for resources that would deliver in 2029 and beyond, depending on what the time frame and the ultimate Action Plan says. But there's just not enough time to do a new RFP or alter the existing RFPs for resources in 2028 and earlier.
Gridworks continued.
Does that address your question?
New Mexico State University continued.
Halfway. So, you haven't baked those assumptions into the models yet even though you can't change the RFP. The models are still sort of open and choosing the best thing? So that's what I'm confused about.
PNM continued.
So, the 2026 resources and those specific resource types and sizes are already explicitly put into the IRP model. We have not finished our 2027 or 2028 RFP evaluation. So, we have not put in specific resources that result from that evaluation into the IRP model yet. We're letting the IRP model fill out with generic resources available in that timeframe.
We do not have time to restart the RFP or issue a new RFP and still actually get resources online in time for 2027 and 2028. So, while we're using generic placeholders, the actual resources that will be put into a Commission-filed docket for approval will be coming from that RFP that is already active, and not from a new RFP.
I hope that that clarifies.
New Mexico State University continued
Yes, excellent. That's a good answer. I hope that can be clearly explained in the RFP text itself. Thanks.
Asked by Pine Gate Renewables on August 31, 2023. View meeting information here.
Initial Response: PNM
In the base technologies case, the new resource options are limited to wind, solar, and storage, but it does still include our existing thermal fleet. So, it's got carbon emissions associated with the existing thermal fleet and all of the carbon emitting resources that are still operational in 2039 that then retire and stop running in 2040 and beyond. But the base technology only really refers to the types of new resources that we allow the model to choose from.
So, a good way to think about it is, is depending on what new resources are added, certain new resources will have greater effects on the way the existing resources are operated than other new resources.[Noting our earlier] point about wind, it has extremely high capacity factors overnight and in the non-summer months, and so it can actually replace certain energies coming from combined cycle units that will be running overnight instead, and causes a decrease in the carbon emissions from the existing fleet, whereas just solar and storage would have less of an effect, especially short duration storage.
Similarly, if you were to add carbon capture, such as Afton CCS, that is a way to abate carbon from an existing combined cycle unit and would cause carbon and reductions that would not be available to the base technologies case because carbon capture was not in available technology.
So, the only the only cases that have lower carbon than base technologies are those cases that have CCS, or the wind expansion, which allows wind to come online earlier than in the base technologies cases.
Gridworks continued.
Does that address your question?
Pine Gate Renewables continued.
That answered the question. Thank you very much.
Asked by a member of the public on August 31, 2023. View meeting information here.
Initial Response: PNM
We do not have that future. The National Carbon Policy future assumes that we've got to be totally carbon free by 2035. There are some other assumptions like accelerated adoption of EVs [electric vehicles] and more behind the meter solar, but there is no future that encompasses sort of an economy-wide electrification, zero carbon outcome. So, I would say the National Carbon Policy is maybe the closest thing we have to that.
We also have sensitivities where we'll look at increased electric vehicle adoption on its own, or a high rate of behind the meter solar adoption in isolation. We can look at bits and pieces of something that might go into a reality like that, but the answer is, no, we don't have an all-encompassing electric economy-wide electrification future.
I think the key there is also we need to take a look at what the current policies on the landscape for New Mexico, or the U.S. overall, are as well as the timeframe for those. There's currently no known timeframe that would require any economy-wide decarbonization within our planning study period.
We are taking a look at some things that would accelerate certain targets, but PNM is beyond the control of mandating customers switch to all electric heating or mandating all electric vehicles from this point forward.
So, we're working with the best available information we have that could affect our system and how we respond to it, not suggesting that we have the magic ball to create an economy-wide decarbonization.
Gridworks continued.
Does that answer your question?
Member of the Public continued.
It does. It's not the answer I was looking for.
I am going to put in the chat a peer reviewed scientific paper that does that analysis for all U. S. states, including New Mexico. I encourage you to go look at that. That will be in shortly. Thank you.
PNM continued.
We can definitely take that into consideration for future IRPs.
Asked by NMPRC on August 31, 2023. View meeting information here.
Initial Response: PNM
The model does a cost minimization optimization based on all the inputs that we have for storage. So, on the relative cost of storage, relative efficiency, the long duration storage technologies tend, while they have more energy capability, to be a bit lower efficiency than the battery storage.
There are just a lot of things that the model is optimizing against.
It's a tradeoff between the various factors—cost, reliability, emissions, all of those things--and it's coming up with what the model believes is the most representative mix of a best portfolio.
It's very intuitive as well, because if we think we're going to need some short duration storage on the system, no matter what the scenario--because we're going to use that short duration storage for intra hour and day to day operations--we're going to want to have some longer duration stuff that's going to help us with ensuring that we've got enough energy
that, on a Monday when it’s super sunny, to use on a Thursday when it's cloudy.
And then we're going to want to have seasonal build up over time when we can capture excess renewables in the spring and use it in the summer and the same thing in the fall and use it in the winter. So, there are different use cases for different durations of storage.
NMPRC continued.
My takeaway is that the cost and reliability and efficiency of long duration is still emerging. It's probably more expensive and less efficient still than short duration.
PNM continued.
I think the key to think about is that all of the different resources have different costs, different efficiencies, and other attributes. So, just like in a traditional system, the optimal mix was never 100% coal or 100% gas or 100% nuclear. But it was a mixture of them because you had different costs tradeoffs, resources are added at different points in time. You wanted to have fuel diversity and they would provide these, these various balances, throughout the system.
The same is true for different types of energy storage. You don't have a one-size-fits-all solution, nor do you want a one-size-fits-all solution. There are all of these different tradeoffs, and you want to have diversity in types of resources and locations and durations and efficiencies--all of these things to make sure that you are capturing each of those attributes and able to best optimize the operations of your system with those.
Asked by Western Resources Advocates on August 31, 2023. View meeting information here.
Initial Response: PNM
We've assumed that CTs have a TRL [Technology Readiness Level] of 9. And the reason that we asse that is because we know that it is highly likely that they will be able to burn an alternative fuel come 2040, whether that's hydrogen or renewable natural gas, or some other type of non-carbon emitting fuel.
It's really CTs that we will convert to a non-carbon emitting fuel. It doesn't have to be hydrogen.
We’ve assumed hydrogen as kind of a higher cost version to be conservative because while there are turbines today that can burn 100 hydrogen--for example, B class GE series turbines—the turbines that we're modeling right now as aero derivatives would require changing out of certain … infrastructure--blades, fuel, injectors--in order to burn hydrogen. There are scenarios where you would have a non-carbon emitting fuel that wouldn’t require that, that would be less costly than what we're assuming here for the hydrogen conversion. And then the hydrogen fuel costs itself.
Also, there is the timeframe. CTs are a known proven technology. They're not converted to burn hydrogen at 100% level until 2040. There's more time to allow the effects of the IRA [Inflation Reduction Act] to allow a more fully mature hydrogen economy and produce the necessary equipment for hydrogen.
But there's always the fallback of renewable natural gas or captured methane or other such things. So, there are a number of things that we're considering, and why we would use a TRL level of 9 here; where for the green hydrogen scenario, as a tradeoff, we were using a TRL of 5.
Gridworks continued.
Does that answer your question?
Western Resource Advocates continued.
That answers my question.
Asked by Western Resources Advocates on August 31, 2023. View meeting information here.
Initial Response: PNM
We stuck with firm capacity. So, it does make up a larger proportion, 256 out of the name plate, as a smaller proportion … and it's called 256 firm out of the total firm capacity.
So, we've used firm, capturing a bit of what you're saying, and I hear that may be it makes sense to think about how critical it is. We think that firm kind of captures the nature of critical.
The firm is relative to the amount of perfect megawatts that we need and we get out of those resources. So, when we talk about the criticality, each one of those firm megawatts is equivalent to each of the other firm megawatts in the value they provide. The difference is how we want to rely upon those from a TRL perspective.
So, we probably misspoke earlier. The total amount of firm capacity out in 2040 is somewhere around on the order, on a current trends and policy basis, of 25 to 3000 megawatts. It's got our peak load plus the reserve margin of firm capacity, so it's really like 256 out of 2600 or so megawatts.
Western Resource Advocates continued.
A percentage.
PNM continued.
Yes, so using firm does create a larger weight for that newer technology. But even so, 10% is not nothing but it's not everything either.
Western Resource Advocates continued.
Yes. I was just thinking--it might not matter as much anymore--but if you lose that 10%, if that .5 turns out to be 0 because it's not available, that portfolio doesn't work.
So, I was just thinking that the weight should be more than it's component of firm capacity.
PNM continued.
I would caution to say that it doesn't work because we will certainly have more than 10% of reserves. It certainly depletes the amount of reserves, but the system is designed in a way that it can operate with a loss of 10% of the resources.
Western Resource Advocates continued.
Ten percent of firm resources, though.
PNM continued.
Yes, it could operate with a loss of 10%. So, the LOLE studies and the PRM calibration get the firm megawatts, and so if we're using 16, 17, 18% reserve margin, that's on a firm capacity basis. Even if we were to lose 10%, we're still going to have 6,7,8% left if everything else is still not an outage.
And that's how we look at designing the system. We know that that amount of reserves is going to have to grow over time. And we would certainly take into account the technology readiness when looking at setting a reserve margin or LOLE characteristics going forward. But based on where we're sitting here today, even the loss of a resource that would make up 10% of our system would not put us below what our load survey capability needs to be.
Western Resource Advocates continued.
Thank you.
Asked by a member of the public on August 31, 2023. View meeting information here.
Gridworks Response:
Thanks. Appreciate that.
Asked by a member of the public on August 31, 2023. View meeting information here.
Gridworks Response:
Great. Do you have some thoughts about how to measure the effectiveness of such an information system, or do others have thoughts about that?
Member of the Public continued.
Not at the moment, but that doesn't mean I can’t come up with something in the future.
Asked by a member of the public on August 31, 2023. View meeting information here.
Initial Response: Gridworks
They're all fair game for collecting at this point. They are fair game for submitting and for us documenting in the Gridworks report that we do. The items that are required to be responded to by the utility are going to be related to the first category that you describe.
I like the way you parse them. The first, the modeling insights results from the modeling and the resulting capacity additions, those are the ones that relate meeting the Statement of Need as defined by the Rule and are things that the utility will be required to respond to. The other two categories--process improvements for the next cycle, or
just overall PRC kind of changes in the requirements for this process--are also things that we can document that are not required to be responded to by the utility.
Is that helpful?
New Mexico State University continued.
Yes. And you identified a report that Gridworks plans to submit to the PRC. So, I think it would be wonderful if this stakeholders group could work with you on that and have an explicit review of those inputs.
Gridworks continued.
Yes, absolutely. Our deliverable to the PRC under this process is a report on best practices or things that which should be considered to be done differently in this process going forward. And so we'd be happy to take stakeholder input in that. That is part of the process for our very last meeting that's scheduled in December after the IRP is submitted. We're going to have a meeting to collect some of your thoughts from the stakeholders, and we can also entertain the idea of review and conversation about that draft report as we put it together--I think that's going to be in the January timeframe.
Thank you for offering that.
Asked by a member of the public on August 31, 2023. View meeting information here.
Gridworks Response:
I greatly appreciate that comment. That is part of our analysis that Gridworks will do for the Commission on what kind of groups participated in this process, where we reached out and were unsuccessful in having participants of important groups. We will say something about that as well because we tried very hard, as many of you know, at the beginning of these meetings to offer input as to who else needed to be at the table.
We did quite a bit of reaching out and we were going to do another round of that as we complete this process.
So, I think your suggestion is really a good one. And any thoughts people have about ways to do that would be great. We will also give some serious thought to that in particular as it relates to disadvantage communities and others that we really want to be part of these conversations.
Asked by New Mexico State University on August 31, 2023. View meeting information here.
Initial Response: Gridworks
Great. I'm glad to be very, very open to your submitting that as a suggestion. I think that would be seconded by a couple other stakeholders who aren't here today that suggested similar kinds of efforts. So please offer that as a suggestion. I think that's a good idea.
PNM continued.
I believe we heard others comment during some prior meetings on the creation of some pilot programs to test certain technologies. And if that's really the direction you were thinking, maybe the way we word it is ‘PNM to file with the Commission for approval of a pilot program for examination of new technologies on PNM’s system’ because those things are not without cost, right?
New Mexico State University continued.
Yes, that's the tricky part. But right now, there is probably a lot of DOE federal money available to do things that won't cost greatly, so I think you have both options.
Asked by Western Resource Advocates on September 28, 2023. View meeting information here.
PNM Response:
Yes, that's correct. And they're rounded to whole gigawatts. You'll be able to download all of the detailed information from the Venue website. You can [consider them] gigawatt by resource type or by technology type.
Asked by NM RETA on September 28, 2023. View meeting information here.
PNM Response:
So those are some questions that also got brought up during our rate case. We do understand that over time we are going to need to develop more different types of tariffs and those are on the table.
Those do not exist today for residentials. Those are a part of our time-of-day pilot for a small commercial.
There are a number of things that we'll need, all of which are currently being looked at. There are a number of different things that would need to be put in place in order to do those correctly. Some of it is going to be a full rollout of AMI. Others will need to be changes to the overall billing system, especially if we want to go to a real time pricing rate or something that allows for more dynamic type pricing
We will continue to look at this and push those forward as we can, but the accelerated viewpoints that folks would like to see have to be balanced against the realistic expectation of how long it takes to roll out changes through metering equipment, billing equipment, and other necessary technologies needed to facilitate those types of rates and tariffs.
Asked by SWEEP on September 28, 2023. View meeting information here.
PNM Response:
When we run the simulations, they are all run in an hourly form. We did not go through and examine that for the purpose of putting this presentation material together.
In running this through an economic model, as opposed to a reliability model, this will be called on the basis of economics and also garner some production cost savings. That does not necessarily correspond with the specific hours you would think for reliability, mainly because, when we're looking at the way different tools work, when you're utilizing a capacity expansion tool such as EnCompass, the reserve margin requirement is a proxy for reliability. We still need to run it through our loss of load probability model.
So, what this is utilizing is the ELCC for demand response and allowing that to be counted towards the planning reserve margin requirement and that is the pseudo for reliability. And then it will just get dispatched as needed, for economic reasons, throughout the course of the year.
That's different than how we will actually operate it. We only call our demand response resources when we really think that we would want to utilize those for reliability reasons. It's less about economics because we don't want to see a complete fall off of our program.
If we called our programs every single day, we'd see attrition rates that would be astronomical, and would lose participation in the DR programs.
Asked by a member of the public on September 28, 2023. View meeting information here.
PNM Response:
Community solar is just modeled as any other standalone solar. It's on the utility side of the grid. It doesn't provide any reliability whatsoever, basically, because it's not paired with storage.
And, yes, anybody who's utilizing community solar is still leaning on the grid whenever the sun's not shining.
Asked by Western Resource Advocates on September 28, 2023. View meeting information here.
PNM Response:
Thanks for the question.
PNM intends to probably do, or propose to do, a couple of different types of RFPs. One would be an all-source RFP for more proven technologies that don't have the lead development times We’d probably do a more targeted RFP that would look for resources that do require that additional development time, or perhaps, say, for wind, that requires the development of an additional transmission line, and perhaps do something a bit more targeted there--due to the amount of time it would take that some of the other types of resources would not.
We will want to hear everybody's feedback as we get into the Action Plan discussion, but I do not think it would be appropriate to restrict solicitations and market analysis to just what comes out of the IRP because we probably would be shortchanging our customers the economic value that could be provided through a more broad competitive solicitation.
Asked by NMPRC on September 28, 2023. View meeting information here.
PNM Response:
We will not be referencing wind, solar, or those six technology types in the Statement of Need. It's not our proposal.
It's our proposal to reference the three buckets of low cost, carbon-free energy resources, dynamic balancing resources, and firm dispatchable sources, recognizing that there are different types of technologies that fit into those buckets.
So, just to be clear, that's how we envision utilizing the bucketing approach for Statement of Need, and then breaking it down by the timeframes.
Asked by a stakeholder on September 28, 2023. View meeting information here.
PNM Response:
As far as the new capacity that would be added during the Action Plan period, not all of it is under contract, but the RFPs that will be used for those solicitations have already been issued and have closed. We are currently evaluating those RFPs.
We should be filing very soon, in the next 30 days or so, the application for the predominantly storage and a little bit of solar resources … that would deliver by 2026, and we are currently undergoing our 2027 RFP evaluation.
So, while not all of that is under contract, the RFPs that will be utilized for those resources have already been issued, closed, and are being evaluated.
Asked by New Mexico State University on September 28, 2023. View meeting information here.
PNM Response:
My concern about adding CTs is that their use as a carbon-free relies on a high degree of uncertainty, so they are likely to be stranded in 2045. That's too early of an assumption to be made because assuming stranded cost is an assumption about what the Commission may use for depreciation rates of what other technologies are available, the likelihood of conversions.
And just as much as someone might hypothetically say that while a CT could be stranded, if you were to invest money in some other type of new technology, that doesn't end up providing the value, but we try to go with something that's less tried and true, you have the similar risk of having stranded cost or, if it's not stranded, you're not getting the value that you would hope for out of those types of assets.
So, we do recognize that, as we move through a carbon-free transition, there is inherent risk in terms of how you decarbonize. I don't think anybody today [could] say we know exactly how it's going to look in 2040. What we're trying to do is balance those risks.
And if stranded costs is one of the biggest risks out there, there are many different mechanisms that can be used to balance that stranded cost risk.
One other comment. [This refers to] depreciation rates.
Whether you have, say, a 20-year or a 40-year depreciation rate, the net present value of that investment, assuming the same rate used for amortization of cost as well as discounting of those costs and a net present value calculation leads to the exact same net present value, other than the effect of marginal income taxes.
So, when we're talking about investment decisions, whether you assume a 20-year or 40-year depreciation rate, it's not as influential as one might think.
Asked by New Mexico State University on September 28, 2023. View meeting information here.
PNM Response:
A bilateral procurement, as opposed to releasing a request for proposals to the market and competitively assessing all of the bids against each other, would be a one-on-one negotiation with a set counterparty outside of a competitive process.
PNM will not entertain a bilateral procurement because that is not in the best interest of our customers.
Asked by a member of the public on September 28, 2023. View meeting information here.
Gridworks Response:
We invite others who may have suggestions about how to make this a tangible action item to please get in touch with us or with the stakeholder who raised the issue.
They have been a very consistent and effective voice in calling out the need for this. We just haven't yet come up with a language for making it tangible and measured against compliance metrics.
So. we're welcoming help on that.
Asked by NMPRC on October 6, 2023. View meeting information here.
Initial Response: PNM
All of that information is derived from the modeling outputs that are posted on Venue. You would need to be a bit more specific.
If you were to go to the data on Venue and compare how we grouped the resource types. For example, we said, low cost, carbon free resources are going to be wind, solar, energy efficiency. So, you would have to total up the amount of incremental builds of those resource types on the different scenarios. And then for those specific time periods, those would then equate to what was on the bubble charts.
When you get to the end of the period in 2040--the bubble charts that we showed were kind of cumulative across time. So, you saw what the cumulative builds were between 2023 and 2027 and then you saw cumulatively what came on, including those periods from 2028 to 2033, and then you saw cumulatively what came on from 2034 to 2042.
If you added those pieces up to 2040, those would be what appeared in the 2040 installed capacity if you compared the corresponding scenario. So, if you're talking about, for example, just base technologies, only scenario 1, you'd need to compare the scenario 1 outputs from those time periods, building up. And then in 2040, that would match what was in the slide for total installed capacity, recognizing that total installed capacity is not just incremental builds; that is the entire capacity of system, including what is currently on, plus what has to be added over the planning horizon.
Gridworks continued.
Would it make sense to share one of the bubble charts from the September 28 meeting [so that everyone, including new participants, can see the logic of the bubble chart range]? [Your team described] a range of bubble locations, depending on what you assume as the contribution from various technologies.
PNM continued.
So, this is new installed capacity, basically through the Action Plan period. So, [it is the] potential range of new capacity by 2028. So, you can consider that either as of January 2028 or December31, 2027--up through the end of the Action Plan period. This is for the CTP or current trends in policy.
So, in that four-year period, under our current trends and policy future, we saw, depending on what scenario was, up to 1000 megawatts of new solar being added. No wind, some demand side resources, a fair amount of battery that ranged a little bit across scenarios, no long duration storage, and a little bit of natural gas, depending on which scenario we would be looking at--there were some scenarios that allowed new natural gas and some that did not.
And so, the ranges [on the slide] represent more the current trends in policy future. There were five different scenarios that we looked at. The ranges represent cumulatively new capacity. This does not assume any of the existing system. These are all new additions, including those that have been approved but have not come online yet, between today and the end of 2027.
Then, by 2032, this builds on top of the last slide. This is not just incremental from the last slide. This is incremental from 2023, including the new things that are going to come online that were approved but not online yet, the other builds that were also included on the last slide, and then what in addition.
So, from the 2028 to 2032 timeframe, across those scenarios, there's now a range of additional solar that would come on. Some scenarios do see some wind come on, some do not. There's more DSM. There's another range of battery. We see some ranges of long storage, and still a small range of natural gas.
And then it’s the same context as we get through the 2040 timeframe. It we just see as we move into 2040, then from 2033 through 2040, the variation across scenario starts to get much bigger because now we're hitting that zero-carbon target by 2040, and you start to see the tradeoffs of the different technology types that could help get you there as well as the amount of additional wind and solar that we need to meet the renewable portfolio standard of 80% by 2040.
So, that's how you would think about these. But the key here is also that this is just incremental builds from our existing system, as it sits here today.
Whereas when you go to the 2040 total installed capacity for a particular scenario, as referenced in the question, that would include incremental builds plus what is already a part of our existing system that is not removed from service by the time we get to 2040.
And all that information is found in those modeling output files that are posted on Venue.
I'll [also] point out--just to try to translate this to the Statement of Need—we are not proposing to call out solar, wind, demand side management, battery, long duration storage, natural gas, explicitly. What we would propose to do is say, “We need to get somewhere--if we total these then up between a range of 2000 to 3000 megawatts minimum of low-cost carbon free energy resources that could be comprised of these different types,” as the way we would think about it through 2040.
For a Statement of Need, we wouldn't want to be so prescriptive to say that it has to be a combination of solar, wind, and DSM in these amounts, because we don't have market bid data that we could transact on. We want to make sure that we're always going to do the best combination of resources from an RFP, from a competitive solicitation, and not pre-subscribe what the exact amount of any existing resource type would be.
Asked by NMPRC on October 6, 2023. View meeting information here.
PNM Response:
At this point in time, there are not. Now we will continue to refine everything. And so there might be small changes to the numbers. But nothing that I would say is going to be substantive.
For example, these are some of the numbers that just came out of the EnCompass model. But further on in this presentation, we noted that if we want to normalize for LOLE, and so if a portfolio was too far away from that point 1 LOLE target, we'll make adjustments to it to reflect that we could add or subtract capacity to make sure that when we compare net present value of revenue requirements, it's done on an equal LOLE basis.
And again, all of this information is on Venue. If you go to the data on Venue from the meeting on September 28, all that can be totaled up for 2040 and you can compare to see if there's any minor differences. So, all of the information is there--100 percent transparent.
Asked by NMPRC on October 6, 2023. View meeting information here.
Initial Response: PNM
Well, ultimately, that comes out of what gets filed in the IRP as the most cost-effective portfolio. Given what we're seeing on the trends right now, our current thought would be to issue an all source RFP for resources that could deliver between 2029 and 2031, recognizing that the way the procurement portion of this rule works--and I'll caveat that that is still under review from the Supreme Court, so that could change.
But the way that rule is currently written, once we file the IRP, then there's the 120-day comment period for acceptance from the Commission [Public Regulation Commission].
Once it's accepted, if we do then intend to issue an RFP, we would need to file the RFP or RFPs that we intend to issue with the Commission and the IRP docket. There will be a comment period on the instructions to bidders. Once we go through that comment period, then we can actually issue the RFP to the street.
Now, there are some complications, of course, if the IRP does not get accepted, because then we're supposed to wait to do anything until we revise it and get acceptance. And some of that can interplay with the timeframe that it would actually take to issue an RFP, receive the results, evaluate it, and get a case filed.
So, there's a little bit of interesting dynamics between how long the process to evaluate an RFP and get a resource approval, [what] construction is versus the Action Plan period, and some of those things that are kind of a side note.
But [regarding] the RFPs themselves, what we were envisioning, based on what we put in the presentation last time, was two RFPs: one that would be targeting any resource that could deliver between 2029 and 2031. That would be an all source RFP.
In our recent all source RFPs, the responses have still mainly been lithium-ion storage, solar, perhaps wind, and some natural gas options, then some demand response options, but there hasn't been much in the way of those new and emerging technologies, longer duration assets that take more time, for example, like pumped hydro that might take eight to 10 years of development time.
So, the other thought would be what we're seeing right now, if we went back to the Statement of Need slides, there was a strong need from the modeling, showing that long duration storage would help in that 2028 to 2033 timeframe.
So, a second RFP could be issued that would be specific to longer duration storage and/or long lead time technologies that would not be able to deliver in 2029 to 2031 but would need to start development activities sooner in order to deliver, say, between 2031 and 2035.
So, that would be the distinction between the two RFPs, as well as going and doing some additional engineering work. For example, do we need to build? And we know the answer is yes. But if we want to get more wind, do we need to start doing some permitting work on a transmission line in order to have the delivery system in place if we want to access new wind out of these?
So, that's kind of the distinguishing factor I would say between the thoughts on the two RFPs: one of them all source, near term, likely going to have the common technologies; another one being a little bit thoughtful, more forward looking and specifically seeking some of those things that are either those not quite mature enough technologies, or require significant development time in order to get them to deliver in the 2028 to 2033/2035 time period.
Gridworks added subsequently.
The RFP documents will go through a separate process and will be available for public comment as part of the IRP RFP follow-up. Take a look at the IRP Rule and see the sequence of steps, but that is separate from the IRP.
Asked by NMPRC on October 6, 2023. View meeting information here.
Initial Response: Gridworks
The bubble chart [that PNM presented] may be included in the PNM IRP, maybe even I the Statement of Need section that describes the range. But, as PNM says, the bucket of types of resources are going be the focus. But [I’ll ask PNM] to respond.
PNM continued.
We will have similar charts to the bubble charts included in the IRP, possibly in the Statement of Need, to help provide that additional color. As you saw on the slides [we discussed], we do have the range of DSM resources broken out. So, I don't know that we need to do anything different here in order to accommodate SWEEP's request.
Asked by NMPRC on October 6, 2023. View meeting information here.
PNM Response:
There's certainly going to be a very detailed appendix that goes through all of the stakeholder input throughout our process, starting back to April of [2022], including a documentation of all the questions that have been asked. Everybody probably is aware now of the interactive Q&A section of our website where you can go and see all the previous questions and answers that have been asked.
In previous IRPs we have had a dedicated section on the results to talk about stakeholder modeling run requests, and we intend to do that this time. I think part of the question will be ‘Do we put every single request into that section, or do we put the most informative requests there and leave some of it in the appendix?’ But all of the information will be a part of the IRP filing.
Asked by NMPRC on October 6, 2023. View meeting information here.
Initial Response: PNM
We will have another meeting on October 19 [2023] where we'll have additional information that's presented. So far, all of the trends of what the IRP model results are showing similar ranges of things across the different futures in terms of similar load growth type things.
Are you asking if you’re going to get an opportunity to review PNM’s final Statement of Need and Action Plan prior to it being submitted to the Commission?
Member of the Public continued.
I think that's pretty close to it--the actual final recommendation of the most cost-effective portfolio. Right now, it to me is still a little in limbo and, unfortunately, I will not be on the October 19 meeting. So, that will not be an opportunity for me to weigh in again.
PNM continued.
It is our intention to have drafts of the Statement of Need and the Action Plan to go through again at the October 19 meeting. Of course, after that meeting, we can still receive feedback.
The final version will be what is filed. I don't know that we're going to have a final draft that is going to be shared and have commentary period on it prior to us filing. That's what this entire process is for and certainly we hope to get a draft out so everybody can review it before we file. But I don't know that we'll have a full draft ready by the 19th, and we still do want to be responsive to additional feedback that we would get at that 19th meeting.
Member of the Public continued.
Will there be at some point a chance to read the full IRP draft before it's filed?
PNM continued.
We intend to try to make a draft of the IRP available for review prior to filing. What that exact date will be will depend on when we get all of the feedback back from the October 19 meeting.
I've had a chance for our internal senior leaders to review everything. And when they're comfortable with it, we will post a version of that to the website for review prior to filing.
At that point, it will be a review. If you want to submit comments, you're always, of course, welcome to but at that point in time, it's going to be in PNM’s hands to decide where we want to go from there.
Gridworks continued.
So, let me add to that. Our intent is to send out whatever version of the Statement of Need and Action Plan is going to be presented at the October 19 meeting a few days beforehand so people can look at it. If there's interest in people having an opportunity to submit written last comments, even after the 19th, I'm sure we can leave that open for a couple of days for additional email input.
There won't be an opportunity to discuss those with the other stakeholders, but we can certainly allow that, but, as PNM says, that's not likely to be the final version. There's still quite a bit of work and review going on within the PM team before that can be considered as final.
And the stakeholder process by the Commission does not require stakeholder review of the IRP. The stakeholder inputs are on the modeling runs, the Statement of Need, and the Action Plan. There's not any formal requirement for the stakeholders to review the IRP prior to filing. But my hat's off to the PNM team for trying to get as much of that to the stakeholders, including the possibility of a draft before filing, but there's no guarantee.
Member of the Public continued.
But it's kind of hard from my perspective as a stakeholder to know what I'm responding to if I don't get to have something that's pretty much akin to the final version of the recommendations. I think that's the point where I have my biggest concern.
Gridworks continued.
That's a good point. I'm going to document that as a possible lesson learned or a best practice--something to change for future. So, thank you for voicing that and we'll document that as a stakeholder request.
We have heard that request from some other folks as well, and so we will definitely include that in our report to the Commission when we report on this process.
Gridworks added subsequently.
[Regarding reviewing the IRP report], the next clear opportunity for stakeholders to review the final document is after it's submitted; there's a 30-day comment period that is allowed for any public comment on that IRP.
So, it's not part of this facilitated process, but it will be registered as comments prior to the commission staff making any analysis or comment, and prior to the commission itself making a decision on accepting the plans. So, we want to make sure people knew that those processes are in place, that are available to folks, and if they should be interested in it, they can certainly have other opportunities [to comment] both on the RFPs that follow and the IRP report itself.
Asked by Advanced Energy United on October 6, 2023. View meeting information here.
Initial Response: PNM
PNM's perspective is to keep as many options on the table at this point moving forward. So, the likely outcome is going to be something that resembles more of the kitchen sink type scenario in terms of the most cost-effective portfolio.
We do see that that performs very highly in terms of carbon emissions, present value of revenue requirements, reliability, all of those things, and diversity of resources is certainly something that is important as well. So, I certainly think that that's probably where we will end up until we get the final resiliency model results done and get across the finish line there. I think that's still up in the air.
But with the Statement of Need and the Action Plan, there's a little bit of a disconnect on those. Where the Action Plan is just talking about the next four years and the resource procurements for the next four years already have RSPs that have been issued, and we're currently evaluating those. And so, most of what will go into the Action Plan is going to be focused on the next step after that and what we think is most viable.
I think what we've seen from this IRP is that there are a lot of different types of technologies that can fill the void in that particular timeframe and ensuring that we keep an eye on the market and technologies as well as ensuring that we issue robust RFPs for that time period to try to make sure that we're not going to eliminate options that are viable is the best way to go forward.
Advanced Energy United continued.
And are there any particular scenarios that PNM is leaning towards?
PNM continued.
Yes, I just said that the kitchen sink scenario is likely going to be the one that we’ll focus on mostly. It is not our intention to take any resource types off the table for competitive solicitations in the future. We want to see how technologies and markets develop around those technologies.
Advanced Energy United continued.
Thank you.
Gridworks continued.
[The slide decks from the last meeting that have all the different combinations of technologies] might be a good place to review those technology options within the kitchen sink.
PNM continued.
What we would say when we look at that, for example, if we see some long duration storage that makes sense, that doesn't mean we'll only consider if it's compressed air in the model results that we're only going to consider compressed air, but there are lots of different technologies that, depending on how their costs curves mature, in the overall operational parameters that can look like compressed air, and so we wouldn't limit it just to that.
Just like we wouldn't limit our look at natural gas options solely to aero derivatives, but we look at linear generators or potentially other technologies. So, what the IRP intended to do is provide us trends in a roadmap of the different types of technologies and resources that could get us there, but ultimately the real decisions are going to be made through the competitive solicitations where we see what the market will bear.
Gridworks continued.
[Here’s the Slide “Five Scenarios for Phase 3 Modeling.] Maybe you can point to, say a few words about what you term the kitchen sink to help us understand what's included?
PNM continued.
The far right one is what we would say is the kitchen sink. And so, essentially, it's not taking virtually any technologies off the table. And the resulting portfolios from this scenario include a lot of different combinations of most of these, but not all of these resources.
So, if we were to issue an RFP based off of that, we would not want to limit it to any particular resource type or resource amount, but we would want to see, based on a competitive solicitation, what combinations of resources coming out of that will best build a need of the specific time period we're looking at and continue to keep all of our options on the table going forward.
So, we don't want to limit ourselves to just a subset of resources because they look okay in an IRP, when that does not have the binding resource decision making behind it, nor does it have competitive market data behind it.
Advanced Energy United continued.
Great. Thanks.
Asked by Pine Gate Renewables on October 6, 2023. View meeting information here.
Initial Response: Gridworks
Thank you. You've covered a lot of topics.
I would ask you to look at the worksheet on the Action Plan, if there are any wording changes--either in things that you would like considered now or things you'd like to consider in the next IRP that are more specific with a timeframe associated with it—you can send those to me by email by [October 9]. That would be great. Or put them in chat now, if you can, if you want to take some time to word it.
We're looking for clarity. ‘Use a better transmission model’ is pretty vague, so if you have something specific [provide it]. The same with ‘shared transmission assumptions’ Anything you want to give us that crisps up, or makes this language more specific, please do so.
There's not a guarantee that PNM will be able to act on it. This is, again, stuff coming from the stakeholders. They will consider it as a team and talk with their folks to decide whether it goes into [the Action Plan] But the more clear we can have that language the better. That would be my request.
PNM continued.
In terms of the RFP, specific language, suggestions around the instructions to bidders, is not going to be included in the Action Plan. The Action Plan would say ‘We will issue an RFP for these timeframes and there will be a separate commentary period where you would be able to review and suggest changes to the language. Similar to this process, it's ultimately at the PNM’s discretion what language we would include.
Frankly, I don't know that we would want to consider five, six, seven years out for solar, but you're certainly welcome to offer up those changes in the instructions to bidders language.
[Regarding] the overall modeling, we are open to starting a modeling process pretty quickly, and I'll have to talk to our folks internally about that, just due to the resources that are necessary.
In terms of transmission data, that's probably not going to happen. That's something that is governed by our transmission department and making that available publicly, especially to a developer, is not something that we've ordinarily done, and I doubt it's something we're going to commit to do in the future.
Certainly, there would be the opportunity to review modeling results. If we do start working in the transmission model, there are going to be some tradeoffs because of timing and other such things. But certainly on the developer side, if there's information that you are able to get that puts you on a competitive advantage, that would be something that we would not want to do, to allow through the competitive process. So, we've got to weigh and balance that.
The transmission modeling overall is going to be something that's going to take time to get right within the IRP context and we're certainly working through that. But I would say that to try to get the transmission modeling right within the IRP is going to take an additional six to 12 months of process time. So, that essentially means we're going to have to start doing that work on January 1, if we file on December 15, and we're going to have to make some decisions on where else we can soften our exploratory pieces in the IRP around the number of scenarios.
As I've mentioned, we don't want to take technologies off the table at this point because we think there are lots of other things that are going to be needed to reach carbon free.
Finally, on the ELCCs, we offered up a lot of opportunity in this process for folks to join early on and to get involved in that discussion. We're certainly open to that. We do think there's a very industry standard on the way to calculate ELCCs. It's not really something that you argue over how you do it; it might be arguing over what's the footprint you consider.
We all know we're going to the [Western Resource Adequacy Program] and so in the introduction to [that] going forward, [we] will have to change the different technologies that are done in the ELCC modeling and the different penetration levels. But in terms of the actual mechanics, there's no real dispute over how you calculate an ELCC.
Gridworks continued.
Is that helpful, at least in some boundary conditions that PNM has made?
Pine Gate Renewables continued.
Fairly clear, yes. We'll be sending you an email with some more specific language.
[Also], there's a comment on the PNM side of things [in the Action Plan] about planning for potential additions on PNM’s existing plant sites. I will be suggesting in comments that commitment involves potentially making some level of data on those plan sites available to the third parties.
PNM continued.
That won't happen. We are not going to make our sites available to third parties. That is an unconstitutional taking of our property, and so, unless we were to sell that property for others, we will not make that available.
Gridworks continued.
Thanks for the clarification and thanks for the comments.
Asked by a member of the public on October 6, 2023. View meeting information here.
Initial Response: Gridworks
That's great.
As the facilitators we're not supposed to be contributing content, but I'm going to take a risk and suggest that maybe the action would be that ‘PNM would participate in an information effort led by others’ or something about ‘contributing information.’ The point is that somebody, in addition to PNM, might need to lead this. That I don't know if it comes from the Commission, or it comes from the Governor, or comes from a state agency. Maybe there's an action that says ‘If the state engages in an information effort regarding the transition of our electric infrastructure and the risks and benefits associated, that the utility would consider participating or offer information’ or something like that.
Is that an area where you're thinking could be a possible action?
Member of the Public continued.
I think maybe that's the best that that we can ask the utility to do at this point. I do think then it may reflect back on the Commission itself to assure that the public is informed.
And I don't quite know what the Commission’s own responsibilities are in this area. But for sure, we have a problem in this area and that's what concerns me.
[For example], last week when I listened to [a media program] on community solar, they really couldn't honestly state to the people on the call how power was being generated for them when the solar isn't producing and why people had to be on the grid. They really didn't come clean on that and that's troublesome.
I'm willing to go with a wording like you suggest. I think that’s maybe as close as we can come.
PNM continued.
In terms of trying to get something like that [into the Action Plan], we've got to keep it focused on what's IRP centric as well as what PNM has control of.
So, if it's ‘PNM will host a series of educational events’ or ‘PNM will provide support if the Commission were to open something up.’ I think those are some ideas that we can get around putting in the Action Plan in terms of educational outreach and showing that we're trying to broaden the public’s understanding of some of the issues raised. But having some very specific things in tangible items that we can say, “Yes, this is what we're agreeing to do,” and we can then measure those in a compliance filing with the Commission.
The time-of-day rate in the stakeholder section [of the Action Plan] is really something that's not IRP centric. We are not in control of what rates get accepted by the commission. So, there's probably going to be some mismatch there of what we think we can accept in the IRP versus what's in the Action Plan versus what’s written there [in the draft]. So, the things that we can do have to be within our control as well as they need to be tied to the IRP type things.
Member of the Public continued.
I totally agree with that. And when I made that comment about the time of day, I didn't mean to imply about the rate, as much as just the fact that this is a shift, which is so important, in the change of generation, that's not getting communicated as well as I think any of us would like to see. And that's where I really want to guide that, so in the future we get better inputs and more informed input.
PNM continued.
I think in terms of education, if it's ‘PNM will at least advertise and host three workshops’ or ‘PNM will petition the Commission’ or ‘PNM, if the Commission chooses to open up a public-facing workshop, will provide support as necessary.’ But you have something there that we can say, whatever the key items are we want to do, PNM knows what it is responsible to do in order to meet that requirement of the Action Plan.
Member of the Public continued.
And it could also be that the communities are developing in other areas where this issue could be one of many others. So, [for example], somebody is doing something on housing or something like that, and power would still be an issue [that] could be brought in somewhere.
Gridworks continued.
Thank you. We'll work with PNM to talk about this offline. We'll also document it so it would go in Gridworks report to the Commission about the need for this.
This has come out from our interviews with a variety of stakeholders who agree with you that information is not getting out there, in particular to inform those disadvantaged communities, low-income communities, about this transition.
So, I think there's something to be done there, and if we can't have something that really makes it tangible within the utilities control, we can put it in our Gridworks report to the Commission to suggest something be initiated on this area.
Member of the Public continued.
I’m fine with that. I thank you all for listening to me.
Gridworks continued.
We’re glad to have your insights.
PNM continued.
Thank you.
Asked by Gridworks on October 19, 2023. View meeting information here.
PNM Response:
No, you're not misreading the text and we will break those out separately before we get to the final resolution. When we have another update to this, we will see demand response in the dynamic balancing resource section and just energy efficiency then in the low cost, carbon-free energy, resource section, keeping in mind, once again, this is cumulative installed new capacity.
So, you would not see, the demand response capacity associated with the existing programs, only new program additions.
Asked by Gridworks on October 19, 2023. View meeting information here.
PNM Response:
If there was gas technologies that through our modeling, we saw being utilized more as a balancing resource, as opposed to a we'll call it a reliability firm generating resource, we would put some of those megawatts over into the dynamic balancing resource section, but predominant what we're seeing here is the gas additions are really only being utilized in the modeling when there are these renewable droughts or other things that show an acting more like an insurance policy or break glass in case of emergency type situation. So we thought that would be better to put it into the firm generating resource bucket, as opposed to the dynamic balancing resource bucket.
And just to reiterate the point, though, that is just our new capacity editions. This does not show anything that has to do with the existing gas resources.
Asked by New Mexico State University on October 19, 2023. View meeting information here.
Initial Response: PNM
What we're showing here is 300 megawatts of long duration storage, defining long duration storage as 24 hours in duration or longer. And then there's 391 megawatts of gas resources that are hydrogen capable that are shown. So, right now, that's what our modeling showing, if you want to dig into the more specific results, please take a look at what's been posted on Venue.
Also keeping in mind, the IRP is not where we make resource decisions. This is a planning docent; it gives us some ideas, but the actual ratios, the actual types of resources, the actual procurements are all going to be done through competitive RFPs subject to our procurement.
New Mexico State University continued.
Okay, that was just simply a matter of misunderstanding the [chart]. Thank you.
PNM continued.
The actual documents are also posted on the Gridworks website if you want to download them and take a look at the source documents as opposed to just viewing it on the screen here as a screen share.
Asked by NMPRC on October 19, 2023. View meeting information here.
Initial Response: PNM
That's what we tried to say at the outset, that these are related to the bubble charts. The bubble charts looked at all five scenarios in the CTP future. This is focusing in on the kitchen sink scenario.
NMPRC continued.
Okay, thank you.
And then on the kitchen sink scenario, going back to [August 31, 2023, Slide 26], this is the only information we have on this kitchen sink so far. You only have it for 2040. Then it shows CTs [combustion turbines] plus the linear generation.
Can we get the loads and resources chart now for the kitchen sink now that it's your most cost-effective portfolio?
PNM continued.
All that data is available on Venue and could be put together by utilizing that data. It's not our intention to put together a L&R table and distribute it prior to filing the IRP.
NMPRC continued.
Okay, so in your IRP we'll have an L&R table.
PNM continued.
Yes, that is one of the requirements by the regulation.
NMPRC continued.
So, staff would very much like, and we're requesting, that we get an L&R table for your preferred portfolio as soon as possible prior to filing the IRP. I know you've said several times that we can put that together on our own through the Venue pivot process. That's a little bit awkward, at least for me to do. I'm not trained to do that, and I asse there are other stakeholders that are not as well.
And then to be able to improve your Statement of Need or to support your Statement of Need, particularly for the early years, which is the next 5 years, what really matters is that it's hard for us to understand your cost-effective portfolio without seeing the annual loads and resources chart to start with.
PNM continued.
Thanks. I appreciate that. And we understand what you're saying. Similar to what we've said before, we're making all of the data available if you would like to manipulate that data to put together the charts necessary for you to perform your review. It's all available. We will try to get a draft report posted prior to Thanksgiving, but the L&R table is usually a product of the appendices of the IRP.
I think we've been making as much data as possible available as frequently as possible. And so, I don't know that we're going to drop everything and create an L&R table. At this point, we need to move forward and get our IRP ready for filing.
NMPRC continued.
Okay, thanks. Back to 2042, the 391 megawatts of hydrogen. Are you saying that the gas resources that are hydrogen capable all come on in that year or did they start coming on sometime between what we would see here 2032 and 2042?
PNM continued.
Those are just showing the amounts of total new installed capacity in those years. So, it's not stating that the 391 megawatts of hydrogen capable, CTs, or linear generators, would come online in 2042. but by the time 2042 occurs, that's how much is online. So, those additions could occur anytime between 2033 and 2042, and this modeling for those specific years for those additions could be found in the data on Venue.
NMPRC continued.
Okay, thank you.
And then just so we understand. new gas would not include possible extensions of save Valencia which would not be considered new gas, even though, I believe Valencia may be part of your 2026 to 2028 RFP.
PNM continued.
The assumptions that we've used in this IRP as well as all of our previous IRP is that when purchase power contracts expire, we model them as expiring and see what types of resources seem cost effective to replace that capacity. So, there's no determination right now on whether or not, we would seek to extend or terminate the Valencia PPA. All the analysis that we've done just seeks to say, ‘Well, what types of resources, if we were to replace it, would be cost effective when?’
When we are looking at Scenario 3 that allows new gas additions, we do see new gas additions come in as the likely cost-effective replacement for Valencia. And so that would point out that in an RFP, we would still consider an extension of Valencia or other gas resources as potential replacements there.
NMPRC continued.
And then when I look at under from generating resources,2027, and there is no gas and also no long duration storage, does that mean you don't need any firm generating resources between 2027 and say 2032?
PNM continued.
No. The way that we would look at that is we don't need to add any new from generating resources by 2027. By the time we get to 2032, we have added 300 megawatts of long duration storage. That could have occurred in 2028 or 2029, all the way up to 2032.
We still do have through 2027 and beyond there a lot of firm generating resources already existing on our system. And so given our existing system, and the other additions that we'd be making in the near term, we would not see under this kitchen sink scenario the need for additional firm generating resources by 2027. We do see that need happen later.
NMPRC continued.
Okay, because we don't see a natural gas addition in 2032, is it reasonable to asse that between 2028 and 2032 there's no new gas?
PNM continued.
In that particular scenario, yes. That does not mean we are going to exclude from consideration the ability to add new gas resources in those years, depending on how the economics and other factors in the system play out over time.
NMPRC continued.
Right, because as you said earlier, this is just a planning guidance document.
PNM continued.
And through an RFP process, if there were natural gas resources that were available, and it beat out the deliverability and economic basis from long duration storage, you could see a request for natural gas resources.
Maybe that's the one of the key things that we're trying to use with this bucketing. We're not making a difference between the 300 megawatts of long duration storage and the 391 megawatts of hydrogen capable of natural gas assets.
That's all from generation resources, and by the time we get to 2040, we’re probably going to need 700 megawatts at least of firm generating resources. And it doesn't matter if it's the long duration storage or natural gas or a combination of the two or just one or the other, we need those attributes.
And same thing on the cost energy resources. Over time, we’re not going to make a big distinction between whether there's a little more or less energy efficiency, a little more or less solar, a little more or less wind or possibly some other renewable energy resource.
What we’re saying is that over this time period, we're going to need approximately those amounts of low cost, carbon free energy resources, and it could be in different amounts so long as I meet the overall energy requirements of the system.
Asked by Western Resource Advocates on October 19, 2023. View meeting information here.
PNM Response:
Yes, our intention is to try to get a full draft of the report posted to our website before Thanksgiving [2023].
And we're certainly welcoming any additional feedback comments, et cetera, between now and then by email as well as up to the point of filing. Depending on the comments and when we receive them, we will take under consideration whether we can modify the docents to work those in.
There are no more scheduled meetings or updates. We're going to provide another update to review with everybody. We've been going through the process now for a while. So, I would say continue to submit your comments and we'll review those and consider them as we finalize our report.
It is our hope to have a draft report available by Thanksgiving, more for informational purposes. We will still take feedback, but at that point in time, incorporating feedback becomes more and more difficult as we get towards the end.
This process has been ongoing since April [2022].
Asked by Western Resource Advocates on October 19, 2023. View meeting information here.
Initial Response: PNM
First, I would say that all of that information is currently available annually on the data found on Venue. So, that all does exist already for you.
In the 2020 IRP. we did put together some tables for all of the different portfolios that we examined and one of the things included in those tables was annual CO2 emissions by year.
Western Resource Advocates continued.
Okay, great. I understand that data is online. Just thinking about how this is a critical data point, it's very useful to have it really accessible publicly even to people who haven’t participated in this process and wouldn't be as familiar with going into the background data, Thank you.
PNM continued.
Take a look at Appendix J in our 2020 IRP. That is likely the same or similar format we would use this time.
Western Resource Advocates continued.
Fantastic. Thank you.
Asked by NMPRC on October 19, 2023. View meeting information here.
Initial Response: PNM
The 2027 RFP is still being evaluated. You should not consider just doing simple math to say you can deduce from this plot what the 2027 IRP filing will look like. Once we've got a little bit further along in that process, we will be making presentations to our stakeholders, including staff, on what that resource request will be. But that draws the distinction between what the purpose of the IRP is versus what the purpose of an RFP is. This gives us some ideas.
It's very likely that the 2027 filing is going to be predominantly solar and storage, given what we know about previous RFPs and the landscape right now. But these numbers will not add up to the RFP request for 2026 and 2027.
NMPRC continued.
Okay, I was more interested just in the resource category of resource types. And what you said is that it's going to be predominantly solar and storage, so that that leaves the door open for something else in the firm generating category.
PNM continued.
It all depends on what the economics and other attributes of the resources offered into the RFP show.
NMPRC continued.
Okay, thank you.
Asked by Gridworks on October 19, 2023. View meeting information here.
PNM Response:
I would say that's a bit of an odd one. And the reason I say that is affordable can meet a lot to a lot of different people. And when we're looking at system level analysis, what we're focusing on predominantly is the overall net present value of revenue requirements.
In looking at affordability, there are two or three things--and some of them are still waiting for feedback [from stakeholders] on. One is when we design the portfolios--and portfolios are always designed as a least cost portfolio subject to whatever the resource choices, constraints, and all the other regulations, et cetera are--so, by their nature, they're going to be least cost in that sense.
Now, the question then becomes if we were to say, as we just talked about for resiliency, ‘Well, we don't want any gas, but we want a system that's going to be as resilient as one with gas in it,’ are we willing to pay that additional amount of money and how does that interact with the idea of affordability compared to reliability or resiliency?
We're hoping to still get some feedback from stakeholders and how they view some of these tradeoffs so, we can fill out the affordability piece. But our commitment to affordability is making sure that we meet all of our requirements in the lowest reasonable cost way.
Gridworks continued.
Great, thank you.
Asked by Gridworks on October 19, 2023. View meeting information here.
PNM Response:
Option 1 includes base technologies and Option 2 excludes base technologies.
So, the difference between these two charts would be that the ranges on the above chart that includes the base technologies would allow the upper end or lower end of the range to be set based off of the scenario that only had the three base technologies in it: solar, wind, and 4-hour storage, recognizing that that portfolio, because of the limited amount of resources, would likely require so much more storage, as an example, or so much more solar, as an example. Do we want to allow it to create an upper end or lower end of a range that may not be representative of the bulk of the analysis.
So, Option 2 changes the ranges so that you are not having the base technologies only scenario set the upper or lower balance.
I don't think that PNM would say that the base technologies only scenario would be a preferred approach going forward, and likely is not the right approach, if given the risks associated with that portfolio.
Gridworks continued.
Okay, thank you for that.
Asked by SWEEP on October 19, 2023. View meeting information here.
PNM Response:
Yes, I don't particularly see any issue there. I think part of the question … is whether we would ultimately end up proposing those as resources through a resource filing or as energy efficiency resource through the energy efficiency plan. But PNM would have no issues … [Would this—edited--wording] work for you?
SWEEP continued.
Yes, that was what I was imagining.
Asked by Western Resource Advocates on October 19, 2023. View meeting information here.
Initial Response: PNM
Do you have some specific language you want to try to recommend? We can look at how it reads or is your comment more just in general what you'd like to see.
Western Resource Advocates continued.
In the second to last bullet, where it says, ‘continue advancing grid modernization efforts,’ where it says ‘to support new customer programs’ you could [add] ‘including load management and load shifting.’
PNM continued.
My only question back then is, if we write it like this--including both load management and load shifting, do you believe that those two buckets cover everything? Or are we now being somehow restrictive of things that are not load management or load shifting?
Western Resource Advocates continued.
I think by saying ‘including’ it's not restrictive, but if SWEEP may want to comment on that and suggest that it should appear somewhere else. Your top bullet says ‘to continue to develop and implement cost, effective energy, efficiency and demand side management,’ but I think load shifting would be kind of a new element that’s not captured in ‘continue to develop.’
PNM continued.
Okay, I don't particularly think there's any issues with modifying the statement like that.
Western Resource Advocates continued.
Okay, thank you.
PNM continued.
One thing I'll point out here is that, of course, for anything that ends up in the Action Plan, we have to be able to substantiate with the Commission in progress updates and how we're how we're meeting these pieces.
So, the expectation from PNM is [not] going to be that we are proposing new load management and new demand load shifting programs as the measure of compliance. The measure of compliance here is to continue to advance grid modernization efforts. And so that's where we will be pointing the Commission to in meeting this objective.
Asked by New Mexico State University on October 19, 2023. View meeting information here.
Initial Response: PNM
Do you have some specific language you want to go over mean? Is it a matter of saying ‘create’ and/or ‘participate’ in pilot programs? PNM is not going to go so far as to say we are going to do these things. That's outside of our control to say that we know we can participate in somebody else's program without not knowing what the program is or the clear objectives.
Similarly, we are not going to say that PNM is going to go out and seek specific conversations with specific developers of specific technologies. Whatever we do as a company has to be something that we would be willing to do for everybody. So, it would not be fair for to say, ‘Well, we're going to specifically go out and seek geothermal developers to build relationships with.’ We sent an RFI to market and got no responses, so it's up to the community to come back with what they think they can do.
New Mexico State University continued.
So, if it was specific language, I would say, ‘Reach out to the DOE, ENREL NMNRD, experts on emerging technologies to see how PNM could participate in pilots they are setting up.’
Gridworks continued.
Could we offer something? So, it says ‘explore opportunities for federal and state funding as available,’ you could add on ‘project collaboration.’ So, you could say, ‘explore opportunities for federal and state funding and project collaboration.’ Would that suffice?
New Mexico State University continued.
Yes, I think I would just say ‘with experts in the relevant government agencies.’
PNM continued.
I don't think we want to be so prescriptive to say it's only government agencies. If we want to participate in a pilot program with APS because they have some ideas about how to use additional or excess energy from Palo Verde to generate hydrogen. I don't want to [exclude] those potential options.
New Mexico State University
So, ‘project collaboration with industry experts’?
Gridworks continued.
You could say ‘as available, including, but not limited to,’ and list a couple of entities.
New Mexico State University continued.
That's very legalese.
Gridworks continued.
It just leaves the door open, but you're trying to get people listed with whom you’re coordinating.
So ‘as available, including relevant [government] labs and others’ or something like that.
New Mexico State University continued.
Excellent. That’s what I was trying to get at with my comment.
PNM continued.
I don't particularly see an issue.
Asked by NMPRC on October 19, 2023. View meeting information here.
Initial Response: PNM
I heard a few things there.
The current RFP that we have bids already submitted to PNM for were for 2026, 2027, and 2028. We've talked about the 2026 portfolio and that's going to be filed imminently. We're still evaluating the 2027 resources. The reason why we highlighted 2029 is there’ve been some questions as to whether we could reissue a 2028 portion of the RFP subject to this IRP and the procurement rules under the new rules.
There was no tie previously to IRPs and RFPs, so we can't say that the 2020 IRP served as the basis for the 2026/27/28 RFP.
We did take a look at what our expectation of needs were that came from the IRP, as well as other regulatory filings and analysis that we've done, to inform the megawatt amounts that we have put in for the years in that RFP.
NMPRC continued.
That's where we came down on this matter.
So now let's talk about the 2023 IRP. And so you file on December 15, 2023, and the Commission has 120 days to accept. So, that's about the middle of April. And then if we go to the RFP section of the IRP rule, it specifies that, based on your described Statement of Need, ‘you shall issue the initial issue an RFP in the current IRP docket,’ so that would be this 2023 IRP docket, and that would be within five months of the Commission’s acceptance.
So that means to go forward with items 1 and 2 [of the Action Plan], you'd probably be issuing an RFP for 2029/31 by August 24 [2023]. I think that's about right.
PNM continued.
There are some other considerations to keep in mind as you review Section 17.7.3.12, which is the procurement portion of the IRP Rule. One: Let’s also keep in mind that all three utilities in the state have appealed that portion of the rule to the Supreme Court. So that is still being vetted by the Supreme Court.
After we file the IRP and go through the 120 days of commentary period, once the IRP is then accepted, if we want to issue an RFP, we have to file the instructions to bidders and the form contracts in the IRP docket. There’s a 21-day review period prior to us issuing the RFP, but there are also other provisions in there where you can seek variances from the five-month requirement.
So, there’s nothing that says, if we don’t issue an RFP within five months, we’ve got to wait until yet another IRP is filed. There are variance provisions that allow us to make timely issuances as necessary.
For PNM, we would [probably] seek to issue these RFPs closer to the May timeframe, not the August or later time frame. The timelines for things are getting tougher and tougher, given the supply chains. So, I don’t think that we’re going to wait that much beyond the 21-day period for instruction to bidder comments and form contract comments before we would actually release that to the street.
NMPRC continued.
Okay.
And then the relationship between an Action Plan period and then the period that you go out for RFPs, there's not a correlation there. Your Action Plan period is 2024/25/26, but, as you said, you're already in an RFP process through 2028.
So, you could go out in an RFP for, as you said, maybe 2028 again, but 2029 through 2031 or 2032 or whatever is your belief as to what's prudent for running the company.
PNM continued.
Were you asking me to clarify whether PNM believes there's a linkage between the RFP and the Action Plan period?
NMPRC continued.
I guess what I'm saying is that just because the Action Plan period is 2024/25/26, that obviously does not set your RFP period. Your RFP period is set based on whatever you think is prudent or what you believe is necessary.
PNM continued.
Correct. The Action Plan period is only three years. It is too short of a time period and too near term for there to be anything that would tie the Action Plan towards new resource evaluations for approvals. From the time we issue an RFP and evaluate it and go through the Commission filing process, it's generally a four and a half to five-year period at best.
NMPRC continued.
I hope my questions don’t seem too elementary, but these are matters we’ve been just trying to make sure we understand.
Gridworks continued.
So, did you have a specific language change you're recommending on 1 or 2 or are you just trying to understand the sequencing of the RFP with the IRP action period?
NMPRC continued.
The latter, please.
Asked by NMPRC on October 19, 2023. View meeting information here.
Initial Response: PNM
Yes, to your second question.
The current abandonment proposal for Four Corners was denied by the Commission, and that denial was upheld by the Supreme Court. So, if we want to exit Four Corners prior to 2031, PNM is going to have to file a new abandonment case. Yes. that's true.
There's no requirement to update the IRP if something changes; there is a requirement to file a notification of material change. And so, the question would then be whether PNM believes the modeling in this IRP was sufficient and robust enough to where it would have considered other Four corners dates, or whether we would actually have to file a notice of material change. I believe the requirement on a filing of a notice of material change is how that would change the Action Plan.
NMPRC continued.
Okay,
I haven't really looked at what we're calling the kitchen sink scenario, particularly in the early years, to see where it has the range or wiggle room to have early retirement or earlier abandonment of Four Corners. And I assume you've built that in or are considering that.
PNM continued.
We certainly are looking at different sensitivities that would examine different exit dates; we've talked about some of those throughout the presentation of modeling results.
The notice of material change references the entire IRP document, so if you want a specific citation to it, it's under 17.7.3.11.D. And it talks about the entire IRP and the Action Plan. It is not specific only to the most effective portfolio.
NMPRC continued.
Okay, great.
So, Four corners is modeled up until 2031 in the MCEP [Most Cost Effective Portfolio]. Is that correct?
PNM continued.
The majority of the analysis we've done has looked at Four Corners being in the portfolio through July 6, 2031, which is the end of the current fuel and operations agreement.
We have done some other sensitivities that have looked at a 2027 exit date, as well as earlier in the process, looking at some 2024 exits. So, the MCEP will likely still have Four Corners through 2031, but we will have run a sensitivity case that basically takes that MCEP and augments it to look at a Four Corners exit in the 2027 or 2008 timeframe, consistent with some of the requests from the stakeholders.
NMPRC continued.
Thanks.
Asked by NMPRC on October 19, 2023. View meeting information here.
Initial Response: PNM
We cannot make that determination in an IRP. Those determinations have to be made by the Commission.
If we want to use Valencia as an example, PNM would have to bring forward to the Commission a set of resources to replace Valencia. We would not make a decision about
Valencia without doing an RFP and other analyses to say, ‘Well, what are the better or alternative options?’
Same thing with Reeves or Red Mesa. Similar to what was done with San Juan, as an example the 2017 IRP did come to a conclusion that there would be a benefit to our customers to abandoning San Juan in its entirety prior to the end of its useful life, but the actual ability to do so was not granted until PNM filed a case with the Commission.
NMPRC continued.
Okay, This keeps being a little confusing—or interesting--the relationship with the IRP filings to the RFP because Valencia is scheduled to retire in 2027 and you have an RFP out for 2026-28, So, by the 2026 IRP, isn't the outcome of Valencia already determined by the 2027 RFP?
PNM continued.
The 2027 RFP, no.
This gets into a little bit of the tie back to item 1 and/or 2. The Valencia contract is currently set to expire May 2028, and so it would be the 2028 portion of the RFP. If having Valencia in here, as an example, is confusing, we can certainly remove it.
Likely the decision on Valencia will have been made prior to the 2026 IRP being filed. Reeves maybe, maybe not. Red Mesa, certainly not. There are other things that are going to be on the horizon, especially interconnected to whether there's an ability to get out of Four Corners earlier or not.
So, I don't, I don't want to confuse folks. We are trying to put an example list of resources that are currently in our portfolio, but in the future, we'll need to have an examination.
NMPRC continued.
That's really helpful. And I appreciate the clarification on the voluntary retirement date. For some reason I had it in 2027, so nice to note it runs to May 2028. Thank you.
Asked by Pine Gate Renewables on October 19, 2023. View meeting information here.
PNM Response:
Yes, so when we are modeling our system, if there's the ability to sell off of PNM resources to provide benefits for our customers, that's captured in the present value of revenue requirements under the understanding that when we build the portfolios, we don't allow the portfolios to be built to make economic sales.
Once a portfolio has been constructed to meet all of our internal load obligations, when we run the more detailed production costs, that will incorporate those additional sales revenues.
Asked by New Mexico State University on October 19, 2023. View meeting information here.
Initial Response: PNM
Yes. I would say that if there's no new natural gas plants added, then all of the risks that you would see would just be associated with the regional aspects. There'd be nothing in terms of just PNM sole correlated gas outages because there's no more gas outages or no more gas really left on the system there.
The question would be ‘How much are you relying on buying market power source from gas units to charge storage resources?’
New Mexico State University continued.
Yes, that makes sense. Do you know what portion of the risk that was?
PNM continued.
Given the very small amount of natural gas in PNM's portfolio by the time we got to 2040, the bulk of that risk is more related to being able to charge energy storage from the grid.
And we did a similar analysis to that in the 2020 IRP, so as you reduce the ability to buy market power in the evening you can cycle up storage for early morning ramps; that does lead to change in the overall risk.
New Mexico State University continued.
Yes, that's fascinating to hear you say that. It would be great to see it in the text of the IRP.
PNM continued.
To the extent we have time to work that up, unfortunately the modeling request deadlines have long since past, and trying to work in new results at this point would be difficult.
New Mexico State University continued.
I wasn't suggesting a new result. I was just [talking about] the verbal analysis of the result and what's impacting it--like you just said.
PNM continued.
Okay. Appreciate it.
Asked by NMPRC on October 19, 2023. View meeting information here.
PNM Response:
So, [regarding Slide 15], one, it did show the amount of EUE reductions when we had a market versus not having a market. And I don't think we're doing anything to artificially constrain ourselves. We're trying to know what the real risks are, given what the market will bear.
When we are allowing the market, we are modeling all of the generators, at least, within one tie line away of PNM’s system. We're not saying we can only buy from non-carbon emitting resources. There's no requirement for that. The short-term purchase power is not taken into account for emissions purposes per the Energy Transition Act.
And so, we are modeling the transmission as we believe it’s going to work. We're modeling line ratings as well as we're saying well, ‘What type of market inefficiencies have we seen that we don't want to over promise and under deliver in times of a critical need.’ So, we are modeling transmission constraints, and we are allowing purchases to come from any type of resource.
NMPRC continued.
Thank you.
Asked by Western Resource Advocates on October 19, 2023. View meeting information here.
Initial Response: PNM
The CO2 emissions themselves are just a product of generation and the release rate of emissions for that particular technology.
If you're referring more specifically to the CO2 intensity requirements per the Energy Transition Act, the Commission has not established its rules on how that is to be calculated. That's an ongoing process.
Western Resource Advocates continued.
Yes, thank you.
I'm definitely not asking you to anticipate where the Commission is going to land in that rulemaking, but just in the narrative to explain where CO2 is provided, just a simple explanation of how the model has calculated CO2--what's being represented there, just so it's easy to see if there's any distinction between what's presented in the IRP and what we may later find as a Commission adopted rule.
And I'm not saying that they should be aligned at this time, but just to know what is represented clearly in the IRP data.
PNM continued.
I was trying to differentiate because the calculation of CO2 emissions is purely the product of generation multiplied by a release rate for a given scenario.
If we're talking about how we’re modeling the carbon intensity constraint, that's a different story,
Western Resource Advocates continued.
The carbon intensity constraint in your modeling that will be presented in the IRP.
PNM continued.
We’re not anticipating putting anything out there that says this is a specific formulation of how we incorporated this constraint. We do intend to show the outputs of what the carbon intensity of the portfolios are.
Western Resource Advocates continued.
I'm just requesting that it just clearly state what the CO2 emissions that are shown in the IRP, just to clearly state what that's representing.
PNM continued.
Okay. I would take a look at what we presented in the 2020 in Appendix J.
If there's something there that you don't understand, or you would like to see done differently, perhaps a more specific request could be made. It’s PNM’s intention to show carbon emissions for each portfolio by year and as well as just show a carbon intensity output.
We did not in the 2020, nor is it our intention in this IRP, to put something out there when the Commission is still deciding how it wants to do the rule.
Western Resource Advocates continued.
Okay. I was not asking for that.
Asked by a stakeholder on June 29, 2023. View meeting information here.
Form Energy Response:
Yes. That’s a very interesting question.
That’s not something that we investigated within the scope of this study and we’re not climate modeling experts. But I think generally there is an understanding that with climate change we do expect to see greater variability in weather and a greater frequency of extreme weather events.
But as it pertains to things like renewable lulls, we didn’t necessarily have any findings on that front.
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
[Paraphrased] So, our approach is somewhere between the capacity expansion model. We are using a linked-sample day approach that then is put into a full 8760 optimization for production costs, advanced purposes, to make sure you capture the full effects of the longer duration energy security into a weekly full year commitment approach that ensures that the dispatch of the long-term long duration energy storage is maintained based rolling forward.
And we used a 40-year historical weather approach and our reliability model for multiple calendar years in that evaluation and for developing our ELCCs.
Form Energy Response.
I could just add a little bit to that. I just want to be clear about what was presented here, which is these are modeling techniques that are really applicable to a very future decarbonized energy system but right now a lot of these modeling approaches have not yet been implemented [as] industry standard tools.
So, this is an area for active model development.
I think PNM is using the best-in-class tools and methodologies that are available today and it’s on us as an industry as a whole to really figure out how we can start to incorporate some of these techniques, like 8760-hour optimization, into tools that can really be used in an IRP context.
So, it’s one thing to perform this type of modeling [as] kind of an academic study or research study but the constraints on modeling in an IRP context are very different.
I think that’s something that’s important to keep in mind.
Same Stakeholder continued?
I’m not so sure I got the answer there. My interpretation of what PNM said is that its somewhere in-between your middle approach, which was a linked analysis, and the full 8760 and your recommendation is to do more of a full 8760.
I don’t get the details, but I wanted to move on to a second question which is the 40-year wind history because maybe it was my misperception, but I thought that PNM’s 40-year history was somehow repeating what they’ve seen historically at their own wind farms which have only been in operation since something like 2005 so they couldn’t go back to 1980. Anyways, can you tell me where your wind data came from that starts in 1980?
Form Energy continued.
Sure. So, this data set here was based on historical wind speeds that are available in the NASA MERRA reanalysis data set.
I’m happy to talk more about how we specifically got that data, but yes, correct.
I think it’s important to acknowledge that the NASA data set, for example, may not account for some of the actual site-specific operations, too.
So, this data should be taken with a grain of salt.
Same Stakeholder continued?
Is the scenario produced by minimizing costs over multiple weather years?
We assess that that wasn’t [our representative the money generates the scenarios based on the interval data. We can generate them moments and hours of play how possibly think that wasn’t already approached to them just the rest of them?]
Form Energy continued.
Yes, so if I’m understanding you correctly, you’re saying that what we’ve shown is that historical weather years can vary significantly and so, … like this slide [Slide ?] for example, we’re just picking one weather year. And so why did we pick this one weather year? Is that right?
Same Stakeholder continued?
[Paraphrased] Why is it that you just generated one scenario]
Form Energy continued.
So, in this specific example here we just wanted to show one representative weather year. But in the scenarios that I presented here, these are based on a co-optimization across multiple weather years. So, we’re not picking one just one scenario but rather we are integrating multiple scenarios of weather conditions into the capacity expansion optimization simultaneously.
I think it is important, though, that when we talk about identifying representative scenarios or representative days [we ask]: What does representative actually mean? Are we actually capturing all of the variability that exists in all of the original scenarios?
I think that’s an area for active modeling development and research.
Asked on June 29, 2023. View meeting information here.
Form Energy continued.
Yes. I can just give one quick response, which is I think all of the points you brought up are very valid and very important to think about in resource planning.
But, as you alluded to at the end, ultimately, we cannot capture every single source of uncertainty in the system or else the model size will blow up.
So, we have to make informed decisions on “What are the variables that really drive the portfolio decisions the most?” I think, based on what we’ve seen capturing weather variability, for instance, this is one of those variables that can really shift the needle when it comes to resource planning decisions.
Asked by a stakeholder on June 29, 2023. View meeting information here.
Form Energy Response:
Yes, that is a good question.
I think for this IRP cycle, again, the PNM team has used the best available industry standard models and approaches that exist. So, I think the point of this presentation was not to say PNM should have done XYZ in this last IRP cycle. This is more about highlighting where modeling practices need to shift in the industry as a whole moving into the future.
So, I’m hoping that some of the things we’re talking about now can just spur conversation and further discussion in the future on how we can start to incorporate some of these ideas in an IRP context.
Asked by a stakeholder on June 29, 2023. View meeting information here.
Form Energy Response:
Yes. It definitely does.
In this case study, we modeled Eastern New Mexico wind and Western New Mexico wind as separate resources. And then, for solar, we just used solar data based on Northern New Mexico, using locations where the majority of PNM’s existing solar facilities are.
But it is an important point that there is geographic variation. The problem is, again, if you’re trying to account for every source of variability and uncertainty in the model, the model size becomes intractable.
And so, what really matters is what is going to drive the resource decisions. I think it requires balancing both of those and trying to capture the temporal variability as well as the geographical variability without sacrificing too much on either one.
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
This is a great question.
I assess that means more like: Why did we choose 45 for reliability? Why is reliability a criteria?
To be frank, we sat down and started discussing ideas. When we think about it, we still have the Public Utility Act which requires us to provide safe and reliable electric power at the lowest reasonable cost. Those are still the primary things we have to do.
The Energy Transition Act then came along and said: PNM you’re required to go carbon free by 2040.
All of the portfolios here that we’re designing are going to be able to meet the RPS and the carbon requirements, and we want to do so in a reliable and low-cost way. So, we put the greatest emphasis then on reliability and cost.
[Regarding the weighting for carbon emissions criteria:]
Each one of these portfolios meets the required carbon emission intensity requirements. As we go forward, they all meet zero carbon, they all meet our renewable requirements.
So, when we’re saying, “Well, what does this particular measure of carbon tend to mean?” It’s which ones are doing it quicker? Which ones are doing it faster? Which ones are doing it [at a] more accelerated [pace] than what the state requires.
Because each of these [portfolios] is doing what’s required, we didn’t want to go ahead and say, “Well, we’re going to put this at 50 percent" because we’re already meeting the requirements in every single portfolio. This is kind of the incremental on top of what’s required, which you already know: We’re going to go carbon free.
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
In this sense, reliability is the measure of the incremental loss of load associated with, or unserved energy associated with running, on a deterministic basis, the P50 capacity expansion under a P90 weather forecast.
Keep in mind that this is just scoring for Phase One and Phase Two.
In Phase Three, we’re going to be examining portfolios under multiple different futures, multiple different sensitivities, and then we’re also going to be doing both a full stochastic reliability and resiliency analysis.
So, the relatively simpler approach here on reliability, just measured by a deterministic EUE, is going to get replaced by something way more complex going forward.
But when we’re looking at trying to say “Well, how robust are these portfolios--at least on a deterministic basis,” the measure for reliability is how it performs on an expected unserved energy basis when we add on the P90 loads to a portfolio that was only designed for a p50 case.
Stakeholder continued.
I guess I’m curious if you can get down the level of understanding which hours that happens in and which resources would be running.
[If] there’s an energy [demand that you're not meeting], which hours of the year [is] that occurring in, [and] which resources would you be expecting to meet that demand that can't? So, what would be your options to fill that gap?
PNM continued.
Are you saying if we hypothetically were to add more resources, what would we add?
Stakeholder continued.
Yes. What would be your options to meet that [unserved energy] [versus what is currently there] and not serving the load?
PNM continued.
So, if we look at the heat map of risk hours, until we get way out into the future, [risk is] predominantly going to [occur in] hours 19 through 21--in June, July, and August. Solar is not there at that point. Wind is.
We’ll talk about this in the deep dive.
When we are seeing loss of load, it’s typically in weather years where you do see a wind drought during those time periods. And so, what we would be seeking to call upon is energy storage, provided there’s actually still state of charge in energy storage devices, thermal resources, demand response.
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
Keep in mind that the capacity expansion model was run on a p50 weather forecast.
So, under the p50 weather forecast, each portfolio is designed to meet that .1 LOLE. But when we throw in the P90, we’re putting in something that’s more extreme, more in the tail, and that portfolio wasn’t designed to meet that specifically.
[The question we're asking is:] Do some of these technologies or do some of these portfolios happen to reduce the risk of unserved energy better than others?
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
Yes, there is a carbon price included in the modeling. It was in one of the previous presentations. It’s our mid-carbon price. It’s in the public data set.
It is included in all this modeling, so it is going to influence the resource planning decisions in terms of new investments. It’s going to affect the dispatch of the resources.
When we’re talking about the carbon piece here, in terms of the scoring matrix, that’s just measured on tons of carbon, not a price associated with carbon.
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
That’s a great point to bring up and it probably draws a distinction between what you heard in the Form Energy presentation versus what we’re doing.
We’re modeling 20 years—20 calendar years.
I believe what Form Energy was talking about was just saying, “Well, let’s throw away what happens between 2023 and 2039, and if we can just get to 2040 with a clean slate, where would we be?”
We’re modeling all 20 years that lead up to that. So, if you look at the outputs from any of the modeling or anything, you’ll see how the portfolio evolves over time, how the dispatch changes over time. You’ll have carbon intensity of renewable. We’ll have everything for each year of the 20 years.
What we’re really doing is doing a capacity expansion run that will set the portfolio over 20 years. Then we’re dropping down and doing an 8760 optimization to determine the way we think the long duration storage will operate, doing a full year optimization at a time rolling forward to get the energy storage production profiles.
And then we’ll do a rolling two week over the next 20 years--always hourly 8760--to determine how the unit commitment will work with some of those resources that do have minimum up times, minimum down times, things like that.
Asked by a stakeholder on June 29, 2023. View meeting information here.
PNM Response:
Near term, [the CT] is 100% technology ready. The risk is, really, does the hydrogen economy materialize or is there some other non-carbon-emitting fuel that would be able to be worked out.
We’ve heard some folks from [EMNRD (Energy, Minerals, and Natural Resources Department)] [say they] think there’s enough landfill gas there. Or, if that’s not there, does renewable natural gas develop?
So, it’s a little bit less risky because you have a much longer time before you get to 2040 than earlier in time.
We understand there is some risk there. We’re open to hearing suggestions on how you may want to weight that, but we think that because there’s a much longer time period there
associated with it, that the relative risk is pretty low.
Stakeholder continued.
[My questions is about the] risk associated with natural gas prices - higher and volatility - for essentially all those Phase Two scenarios, because assessing that they may just be gas technologies that don’t convert hydrogen
and then also whether you modeled or considered the stranded asset potential associated with those gas technologies.
PNM continued.
The other thing I’ll add on here is there are currently combustion turbines that can burn 100 hydrogen today. So, we know that the technology can happen. The question is whether it gets there cost effectively.
In Phase One and Phase Two, we are doing our analysis using our current trends and policy future.
When we get into Phase Three, we’ll start introducing high and low gas prices and other things like that.
In terms of stranded asset costs, we’ve talked internally about one of the things we might want to do is say, “Well, what happens if we made some investments in CTs and then in 2039 we make an assumption that you can’t use them anymore and you have to replace them? What will that do?
At that point in time, you’re going to have better technology characteristics. In the future, prices may come down, so there may not be a difference.
We don’t know yet. We haven’t finished that analysis.
Asked by a stakeholder on June 29, 2023. View meeting information here.
Form Energy Response:
That’s a great question.
So, we were performing a true least cost optimization where we provided all of the candidate technologies and allowed the model to select the optimal capacity of each technology without forcing in any technology.
We included the full range of long duration. Only a couple were selected by the model, but we did include the full range of five or six long duration storage technologies, for example, that were in the PNM IRP as well as some of the other technologies.
Stakeholder continued.
In terms of the testing of the linked days, is it correct that you were only looking at two days maximum or two days you linked because I wonder if you were to do a version of this with six or seven days linked, if that might be a more cost-effective approach that approximates for the 8760 results.
Form Energy continued.
In this link day approach, [we created] representative weeks where we took the two representative days for each month and had three days of the peak day and four days of the off-peak day and used that to construct like a linked week. And then we linked all of those weeks together for each month to construct an entire year. So, they were linked into a continuous 8760-hour time series and That’s what was modeled in this study.
One thing I think that I should mention when it comes to day sampling and linking, is I think there is definitely literature research to support that some sample day methodologies can be effective, but what really matters is how are we doing the sampling: What is being captured in those sample days? If we’re just taking like a peak day and an off-peak day that might not actually be capturing what really matters in driving resource decisions.
And so, there are more advanced techniques that can be used to identify periods of the year that really represent--like through clustering algorithms and stuff like—the full range of resource dynamics.
Stakeholder continued.
It’s short yes for the 8760-modeling approach. How would that fit into a competitive bid evaluation if PNM gets like 400 bids?
Gridworks continued.
So, I think that’s a PNM question not a question for [Form Energy].