The Municipals, Cooperatives and Transmission Dependent Utilities (“TDU”) Sector in December 2022 submitted comments raising concerns with draft expansion plan information provided by MISO.  In reviewing expansion plan information provided in March 2023 it does not appear that MISO has made material changes in response to the feedback from the Sector.  The TDU Sector is once again submitting its concerns with the draft expansion plan and asks that these be addressed.  In addition,  members of the sector have identified area specific issues with the draft expansion plan and will be providing separate comments with those issues to MISO.  Overall, it appears that it will be challenging to site all of the new resources currently being added as part of Future 2a.  Given this, as well as the general and specific concerns the Sector has with the expansion plan, the Sector requests that MISO provide updated expansion plan information reflecting feedback received and that another opportunity be provided for stakeholders to comment on the updated information.  The TDU Sector feels the importance of the expansion plan to LRTP planning is worth taking additional time to help ensure information used is reasonable. 

Provided below are the TDU Sector’s initial thoughts submitted in December 2022 on MISO’s draft Futures F2A expansion results.  As noted above, the sector asks MISO to address these concerns.  The sector appreciates MISO’s efforts on this aspect of the planning and overall continues to be supportive of the LRTP effort.  We look forward to continued discussion with MISO on this work.

• Overall, the TDU Sector does not support the draft expansion plan provided by MISO and requests that MISO significantly increase the amount of flexible resources represented (e.g., energy storage and RICE).  In addition, MISO should not limit storage to merely 4-hour duration batteries.  In developing a resource plan that looks 20 years out into the future MISO should recognize that technology will advance and options for flexible resources that can be added to the system will increase.  The sector requests MISO add a more generic flexible resource type to the mix and perform sensitives around the impact to transmission needs based on the level of flexible resources added to the system.

• MISO’s draft expansion plan over-emphasizes wind and under-emphasizes flexible resources in a manner that we see as inconsistent with realistic and cost-effective LSE resource plans.  The TDU Sector recommends that MISO take into consideration the existing Generation Interconnection Queue and its indication that near-term expansion of solar and dispatchable battery energy storage is likely to outpace the expansion of wind resources.  Assumptions around very large wind additions may become self-fulfilling prophesies to the extent that they lead to very large transmission build-outs in remote wind-rich regions. 
  • Related, while MISO indicated that it did account for declining marginal capacity value of wind, we question whether we can accurately gauge the marginal capacity value of wind with more than 140 GW of wind on the system.  We note also that the economics of storage additions will significantly improve as LMP volatility increases with a shift to renewable generation; this is something that is difficult to appropriately account for in MISO’s capacity-planning simulations.  In addition, increasing storage installation will tend to improve marginal capacity value of intermittent resources.

• In creating an appropriate expansion plan MISO also needs to consider that communications on Resource Availability and Need and the Reliability Imperative are now shaping and driving resource planning expansion plans for LSEs.  Economic considerations are very important in determining the appropriate resource to add to a generation fleet, it is not the only consideration. LSEs have for decades sought to create a diversified resource mix that includes generation resources with the attributes required to maintain reliability.
  • For the 20-year period through 2042, wind is the significant majority of net wind and solar added to the model.  While the 2022 interconnection queue cycle does not reflect resource additions through 2042, it does show that addition of solar resources outpaces wind resources at about 86% (84 GW) of the 98 GW of wind and solar in that queue.  Additionally, the 2022 interconnection queue contains 32 GW of storage (not including hybrid which is 34 GW) whereas Future 2A only has 27 GW of storage (BESS) through 2042.

• MISO should also consider that utilities will focus on adding resources inside their Local Resource Zones for local reliability, local economic developments benefits, and to avoid capacity market zonal separation risk. MISO’s expansion plans should lean towards resource expansion that satisfies the entire Planning Reserve Margin inside that Zone, as opposed to just solving for the bare minimum of Local Clearing Requirements.

• Finally, MISO should adjust the timing of when flexible resources are added.  For example, currently MISO’s expansion does not show material levels of energy-storage resources until 2031.  Given the impacts of the Inflation Reduction Act, the levels of renewable resources already being added to the system and the objective of LSEs to have the right mix of resources, MISO’s expansion plan should show more flexible resources being added before 2030 as well as significantly more flexible resources prior to 2035.

• To the extent Future 2A ultimately includes the features reflected in the preliminary results that are discussed above, such as the large amount of wind, the TDU Sector recommends the use of sensitivity studies within the LRTP Tranche 2 analysis to determine the impact of alternatives to these assumptions as also discussed above.

Currently, ICC staff does not have any direct input Future 2A’s siting recommendations. However, ICC staff does want to express appreciation for the Future 2A update. It is reasonable to update Future assumptions with changes in generation development and retirements, especially as a result of public policy like the Illinois Climate and Equitable Jobs Act (CEJA). ICC staff also asks MISO to report any other state agencies, beyond public utility commissions, are being consulted on siting issues.  

ICC staff is curious about whether load changes will be included in upcoming Futures updates. Much as public policy is shaping retirements and generation, policy could also potentially impact load. Public policies addressing energy efficiency, building electrification, and EVs are increasingly common. Further, outside of public policy, changes in industry – notably the growth of data centers – might also impact load predictions going forward. Given these trends, are there any plans to update load predictions as part of any forthcoming Future updates?

ICC staff is also encouraged by MISO’s consideration of HVDC lines in its Tranche 2 planning. HVDC lines offer a number of benefits, including moving power efficiently over long distances with lower losses and without the need for reactive power consumption. HVDC lines will be an important tool in moving resources from renewable rich zones to load centers. At the same time, ICC staff also supports MISO’s “all things considered” approach to transmission planning. HVDC might not be right in all contexts, and considering a range of line options to address cost, land use, and contingency concerns is a good approach.

Finally, ICC staff would like more information the impact the additional siting proposed in Future 2A will have on the MISO queue. Will these additional resources be able to clear the queue in a timely manner, to meet state policy goals?

WEC Energy Group submits the following comments in response to MISO's request for feedback on the Future 2A resource expansion and siting.  One item in particular raised immediate concern – the amount of DR for both Wisconsin Public Service (WPSC) and Wisconsin Electric (WE) is nearly 300 MW each in Year 5.  This amount of DR is not consistent with our internal studies which are not picking DR in our expansion plan (especially by Year 5).  We note that other LSEs in LRZ 2 have little to no DR in the Future 2A expansion plan through the 20 year study period.  All LSEs in LRZ 2 should have relatively comparable DR in the Future 2A expansion plans and as noted above, our internal studies are not picking DR.

We also note that the amount of RRF wind units in LRZ 2 (WI/Upper MI) is over 5 GW through Year 20.  We do not believe that LRZ 2 can accommodate this amount of wind.  In comparison, the amount of RRF solar and solar hybrid in LRZ 2 is only 2 GW through Year 20.  We would have expected just the opposite – more solar than wind in LRZ 2.  Despite MISO assumptions regarding the enhanced production tax credit of wind when compared to solar, the 2022 generation interconnection queue shows solar resources outpaces wind resources at about 86% (84 GW) of the 98 GW of wind and solar in that queue.  The TDU Sector made similar observations in their Dec 16, 2022 feedback on Future 2A.  As we requested in LRTP Tranche 1, MISO should, at the very least, perform sensitivity studies with more solar to determine the effectiveness of the Tranche 2 transmission expansion plan.

We are glad to see aggressive capacity expansions especially renewables in Future 2A. There however does appear to be vast differences among the Local Resource Zones (LRZs) regarding their respective capacity expansions. Why are we seeing such large differences between neighboring LRZ’s? An example of this can be seen between LRZ 1 and LRZ 2.

Thank you.

Otter Tail Power Company (OTP) appreciates the opportunity to provide comments on MISO’s preliminary Future 2A siting results. Developing credible Futures is an important part of the LRTP effort to ensure that the final Tranche 2 portfolio of transmission projects is cost effective and can maintain grid reliability.

OTP has several general comments on the preliminary siting results and will also provide more specific comments on the future generators in OTP’s area in the siting spreadsheet.

• Generation siting in North Dakota and South Dakota seems very light. The Dakotas have abundant wind resources, and considering the last few MISO interconnection queue cycles, the Dakotas contain about 37% of requested wind capacity in the West region (ND = 26% and SD = 11%). In year 20 of Future 2A, the Dakotas contain about 11% of the wind capacity in the West region (ND = 8% and SD = 3%). Thus, it seems like the Dakotas are light on wind siting. In addition, the Dakotas are also likely states for siting any new dispatchable gas generation in the north region. Neither of these states contain any new dispatchable gas generation in the Future 2A siting.
• The demand response in the OTP LBA is unrealistically high.
• There is a lack of dispatchable generation to make up for retiring baseload units. Batteries with a four-hour duration will not be sufficient during extreme weather events that may cause sustained high demands or droughts in renewable generation.
• The resource siting should be consistent with current state legislation.
• Retiring generators are likely to replace their capacity at the same location where they have existing transmission rights. There are several examples where MISO assumes OTP-owned resources will retire but MISO shows no replacement generation at those locations.

The Formal Feedback of the Mississippi Public Service Commission regarding Future 2A Expansion and Preliminary Siting (20230310) was submitted as a PDF attachment via email to stakeholderrelations@misoenergy.org.  That email and attachment may be viewed by the public.   

Minnesota Power is seeking to more clearly understand the Futures 2A portfolio for both the energy adequacy  -  hourly resource/load understanding, and the resource adequacy attributes.   

• Showing annual ICAP level retirements and additions is not as useful to understand the resource adequacy attributes. 
• The seasonal accredited capacity by fuel type and peak load requirements would be useful to understand the portfolio resource adequacy attributes. 
• For the energy adequacy aspects, it would be very helpful to see a dump of hourly generation by fuel type, hourly load that is not netted with any renewable resources, net interchange with regions outside of MISO. 
• The effort of establishing the locations for new generation and properly modeling projected retirements is a crucial element of the LRTP study work, but we feel it is important to demonstrate the basic capabilities of a resource portfolio to meet load requirements to make sure the siting effort is based on a viable resource portfolio.  

North Dakota appreciates the opportunity to provide comments on MISO’s preliminary Future 2A siting results. The assumptions MISO uses in modeling these futures are a significant driver of new transmission projects. According to the current tariff on file, these transmission lines are paid on a postage stamp basis by all MISO North customers. Therefore, MISO must make every effort to spread these investments fairly throughout the region. This is especially true since the next tranche will naturally reflect the need for more transmission in states with high decarbonation goal and customers in states with lower decarbonization goals will then be subsidizing those policies. 

Overall, the assumptions for future generation being siting and developed in North Dakota are extremely light and fail to recognize a couple important realities:

1) North Dakota is the only natural gas producing state in the MISO region making it an extremely valuable and logical place to assume development of additional natural gas peaking units. These will be essential for reliable operations into the indefinite future, and North Dakota’s in-state production offers fuel security that all other locations lack. What's more, one such facility that is already planned by Xcel in North Dakota is not even reflected in this refresh.

2) North Dakota has one of the best wind resources in the MISO region, which enhances the reliability, reduces intermittency, and increases the efficiency of wind generators in North Dakota. MISO needs to increase the assumption for wind development in North Dakota.

North Dakota is also concerned with the lack of dispatchable power MISO assumes will be developed in this model. Dispatchable resources, even if they aren’t being planned by MISO utilities, need to be modeled in order to reflect a system that is reliable longterm and has the transmission infrastructure needed to support this essential generation.

Additionally, we echo the concerns raised by Otter Tail Power, MDU and Xcel, specifically:

• The demand response in the OTP LBA is unrealistically high.
• Retiring generators are likely to replace their capacity at the same location where they have existing transmission rights. There are several examples where MISO assumes OTP-owned resources will retire but MISO shows no replacement generation at those locations.
• The futures do not reflect enough resources sited in the MDU territory to support their future load projections.
• MISO should not be planning to add so much wind in northern Minnesota where the wind resource is poor, and should be shifted to North Dakota.
• The amount of solar additions MISO is assuming for eastern North Dakota seems high. The Red River Valley is prime farmland, making it a less attractive location for solar. Wind would be a better assumption there.

The lack of siting MISO is reflecting in the MDU territory is a real concern. MDU is on the western edge of the MISO region and serves load all the way into Montana. MDU is in the heart of the Bakken oil and gas field, making it a natural and valuable location for siting future natural gas generation. Additionally, the wind resources in central and western North Dakota are strong and MISO must not strand the potential of these resources by failing to enhance the transmission infrastructure there. 

Xcel Energy appreciates the opportunity to provide feedback on the draft siting results for the updated Future 2A. We feel that proactive planning efforts, like the LRTP, are an important piece of a safe, reliable, and affordable transition to a clean energy future, requiring a high degree of attention and coordination to achieve the goals of this transition. Xcel Energy remains open, and strongly encourages MISO staff to increase the coordination with the utilities in their footprint as these companies provide invaluable expertise in the areas they serve and ensure company plans are captured correctly. Xcel Energy submits the attached spreadsheet with suggested relocation of natural gas fired resources being sited within the State of Minnesota. While we don’t feel locating these resources within the Minnesota state borders is in direct conflict with the requirements adopted in recent clean energy legislation in the state, assuming these resources can receive approval to be constructed in the state is no longer a reasonable assumption. In addition, we feel that maximizing use of existing clean energy resources, such as existing nuclear generation, needs to be leveraged to its fullest extent and recommend reversing the assumed retirement of two nuclear generation units in the NSP footprint.

• Not included in the spreadsheet are two corrections related to unit retirements. The generation resources located at Blue Lake and Inver Hills have no plans for retirement, but rather, will be replaced on site.

Maximizing use of existing infrastructure can also be applied to the fuel supply of natural gas fired resources. We feel any new natural gas fired generation should be done in such a way that minimizes the need for significant expansion of pipelines and minimizes difference on the transmission system that would result in a different energy source being utilized to fill the need of the assumed natural gas fired resources in the Futures.

• Proposed solutions to Item 1:
  • Relocation of new and expansion of existing natural gas fired resources to 345 kV hubs in eastern North Dakota and South Dakota near existing natural gas pipelines. This represents a more reasonable location to site and permit new natural gas fired generation while reducing the need to review pipeline expansion costs.
  • Relocating these resources as suggested also ensures the transmission system can accommodate a broader ranger of outcomes. If generation happens to be developed in a way that the need covered by the natural gas fueled RRF in the Futures is instead met by some combination of renewable resources and storage, for instance, there would be significantly less variability system impacts than if those natural gas resources were located in there currently proposed locations.

In general, Xcel Energy is also concerned about the siting of renewable resources in the Arrowhead region of Minnesota. This area includes large areas or tribal lands and protected forests that make the siting of such resources difficult, at best. This area has also been found to be a lower value area for the development of renewable resources, having lower average wind speeds and solar irradiance than other areas. Because of these risks and inefficiencies, we recommend MISO work with the local utilities to find higher value resource locations for the renewables in Minnesota’s Arrowhead region, such as central and eastern North Dakota.

• Proposed Solution to Item 2:
  • Relocation of all renewable RRF resources located in northeast Minnesota to locations in central and eastern North Dakota.

Finally, we feel strongly that local plans should be fully incorporated into these model updates to ensure the results of any analysis using these models are reasonable. Xcel Energy has recently filed a Certificate of Need application with the Minnesota Public Utilities Commission (MN PUC Docket # E002/CN22-131) to construct a generator tie line to allow our existing coal generation at in Sherburne County, MN to be replaced primarily with renewables. Failing to incorporate this plan into Future 2A will result in an unreasonable set of models, and any project that is developed from these models would face increased scrutiny and delay resulting from inaccurate assumptions.

• Proposed Solution to Item 3:
  • Increased coordination with Xcel Energy to properly incorporate the Minnesota Energy Connection project into the updated Futures. This project, if approved, will shift the injection point of 2,000 MW of resource
  • In addition to the Minnesota Energy Connection, Xcel Energy has stated plans to replace the capacity of the existing Allen S. King coal-fired generating plant primarily with approximately 600 MW of nameplate renewable capacity through another generation tie line to that resource’s point of interconnection.
  • These two resource replacements need to be considered as base model changes and Xcel Energy would be happy to meet with MISO staff to provide the specifics of each effort.

Xcel Energy appreciates the efforts undertaken by MISO Staff to update the Futures and stand ready to provide assistance in any way MISO staff would need. 

WPPI notes potential issues with a limited number of sites in Wisconsin and Upper Michigan as indicated below.  We would find it helpful if MISO included Bus Name and Bus kV fields in future postings as they provide more accessible information than bus numbers alone.

Finally, we are participating in separate comments to be submitted by our Muni/Co-op/TDU Sector.

Description Short Name Category LBA/Area LRZ State County Y15 MW Y20 MW Detailed Category Source Bus# Site Available for Use (Yes/No) Replacment Site Bus Number
RRF MISO F2A RW: MGE - 1 MGERW1 Wind Madison Gas and Electric Company LRZ 02 Wisconsin Sauk County 189 311 Wind RRF 694099 Identified bus is in Dane Co., ~12 miles and across a major river from Sauk Co.
RRF MISO F2A BATT: ALTE - 1 ALTEBT1 Battery Alliant East - Wisconsin Power and Light Company LRZ 02 Wisconsin Columbia County 75 75 Storage Battery RRF 693885 Very large injection for 69 kV system
RRF MISO F2A BATT: WPS - 2 WPSBT2 Battery Wisconsin Public Service Corporation LRZ 02 Wisconsin Manitowoc County 200 250 Storage Battery RRF 698590 Battery this size is too large for this single location
RRF MISO F2A BATT: ALTE - 3 ALTEBT3 Battery Alliant East - Wisconsin Power and Light Company LRZ 02 Wisconsin Columbia County 100 150 Storage Battery RRF 698201 Battery this size should be connected to adjacent 138 kV bus
RRF MISO F2A BATT: DPC - 1 DPCBT1 Battery Dairyland Power Cooperative (GSE) LRZ 01 Wisconsin Buffalo County 100 150 Storage Battery RRF 680173 Battery this size should be connected to adjacent 161 kV bus
RRF MISO F2A Wind: ALTE - 1 ALTEWD1 Wind Alliant East - Wisconsin Power and Light Company LRZ 02 Wisconsin Iowa County 250 250 Wind RRF 698016 Will cause large overloads at interconnection point
RRF MISO F2A Wind: NSP - 1 NSPWD1 Wind Northern States Power Company LRZ 01 Wisconsin Clark County 800 800 Wind RRF 603152 Will cause large overloads at interconnection point
Grant County GRANTCOP Solar Alliant East - Wisconsin Power and Light Company LRZ 02 Wisconsin Rock County 200 200 Solar PV Committed 693478 Capacity very high for 69 kV interconnection
RRF MISO F2A Wind: WEC - 2 WECWD2 Wind Wisconsin Electric Power Company LRZ 02 Wisconsin Waukesha County 510 510 Wind RRF 699247 This is an aggressive MW target for this site, with urban/suburban development on 3 sides, and modest wind resource
RRF MISO F2A Wind: WPS - 2 WPSWD2 Wind Wisconsin Public Service Corporation LRZ 02 Wisconsin Marathon County 539 539 Wind RRF 699676 This is an aggressive MW target for this site, with lots of river valley and forest nearby, and modest wind resource

• The attached Excel files contain details of the corrections and recommendations related to siting and generators. The more notable corrections are as below:
  • Many of the DGPV sited by MISO are too large to be feasible for the assigned substations and thus they have been split and distributed over additional substations
  • Some of the wind farm additions are too large to be feasible at single interconnection point and thus the capacity has been split/spread over multiple substations 

• Given the widespread concern of premature retirements of coal plants, the Future 2A model assumes aggressive retirement assumptions for existing conventional coal and natural gas plants. MidAmerican agrees with the footnote on Slide 5 of the presentation from the March 10, 2023 Long Range Transmission Plan workshop, where MISO should consider adjusting resource additions to address the uncertainty of MISO’s new accreditation rules. MISO should consider the addition of more dispatchable generation, including natural gas and other dispatchable resources. The pace of resource retirements is another potential adjustment MISO should consider to address this issue.
  
• MISO’s generation cost assumption shows -$30/MWH for variable O&M for batteries in the year 2022. If this is an indication that MISO is assuming PTC for storage, MidAmerican does not believe this is the correct assumption as storage is ineligible for PTCs.  Storage is eligible for ITC treatment.

DTE appreciates the opportunity to provide input on the preliminary Future 2A siting results.  Upon review of the worksheets that contain the additions, retirements, and the siting we have the following concerns:

1. MISO assumes that the originally installed wind sites are to be retired after a set time due to age.  This should be approached with caution as and we recommend that MISO change them to “Out of Study Period” as the sites can be re-powered or replaced rather than leaving a void that is replaced with EGEAS RRF selection.  MISO also takes an aggressive approach to retiring aged gas peakers which should be left in the cases through 2042 (Y20) study period due to no plans by the utility to retire these resources.  In addition, MISO added a considerable amount of RRF wind in Y10.  Is this due to the assumption of the existing wind retirements?
2. The retirements of large fossil fuel plants does not align with our most recent IRP, including planned conversions. 
3. The POI busses for the wind and solar category are not aligned.  It appears that MISO made an assumption that all of the resources are to be located within the LBA even though we submitted specific bus locations. 

Again, we recommend that MISO reevaluate their assumptions on age based retirements for originally installed wind sites and consider recategorizing them as “Out of Study Period” to account for situations where they could be re-powered or replaced.  Additionally, MISO should keep large gas peakers in the case studies through the 2042 (Y20) study period.  MISO should also update the retirement schedules so that they are consistent with the most recent IRP plans submitted by stakeholders.  There seems to be significant misalignment which will skew the analysis of transmission needs.  Lastly, we recommend that MISO reference the bus locations that were submitted by stakeholders for the wind and solar category to ensure the correct POI are utilized in the preliminary siting for F2A.

Entergy Response to MISO Preliminary Siting of Future 2A Resources

The Entergy Operating Companies[1] appreciate the opportunity to comment and provide feedback on MISO’s preliminary Future 2A Resource Expansion Plan.  This document describes the rationale for the siting recommendations in the associated Excel workbook entitled, ”MISO Preliminary Future 2A Siting – Entergy Response.xlsx” (Siting Spreadsheet) and recommends adjustments to the resource mix in MISO South. 

While the Stakeholder Feedback request notes that the resource mix was presented as “final” in the March workshop, Entergy’s comments below also recommend adjustments to the resource mix, given that this is the first time MISO has presented information that is sufficient (and sufficiently detailed) for stakeholders to provide reasonable feedback.  Although MISO provided an opportunity for Stakeholders to comment on the resource mix in November 2022, at that time, MISO did not provide the information reasonably needed for stakeholders to comment on the resource mix.  For example, it was not until the March workshop that stakeholders were provided with even sub-regional level resource mix information, which was only provided at the MISO footprint level in November, and is not sufficient for providing useful feedback. Foreclosing the opportunity to offer feedback on the resource mix prior to providing information noted above, which is reasonably needed to evaluate and comment on that resource mix, would be unreasonable.  For these reasons, Entergy strongly encourages MISO to consider and incorporate the resource mix adjustments recommended here. 

Wind Resources

Entergy believes that wind will play a role in our future resource fleet, as indicated by the ~11,800 MW of committed wind resources in the preliminary siting, excluding the 5000 MW of “committed” offshore wind sited in Louisiana.  Entergy’s comments on future wind installed capacity and siting are based on both the physical potential to produce the forecasted output and the economic potential of developing these resources in the forecasted model years.  Regarding considerations of wind energy resource development potential, Entergy stresses the importance of differentiating between onshore wind and offshore wind, which MISO’s current resource selection assumptions do not.  As discussed further below, Entergy estimates the approximate Installed Capital Cost of onshore wind at ~$1,500/kW and offshore wind at ~$3,600/kW. 

On-shore Wind Capacity Additions

The forecasted addition of ~9,500 MW of on-shore on system RRF wind resources in the Entergy area beyond what is indicated as committed by Entergy is likely impractical and is forecasted earlier than is necessary to meet the relevant Carbon Reduction goals.  The F2A resource forecast contains more wind resources than utility scale solar resources in MISO South.  This outcome is highly unlikely, and this assumption is thus unreasonable, considering the high cost of wind resources relative to alternatives and the poor quality wind speeds in MISO South.  Siting wind in MISO South earlier or in greater magnitude than is realistic would distort the study results relevant to the timeframe of this study and could result in construction of ineffective transmission infrastructure or concealing future system limits.

MISO should share with Stakeholders what has changed to make on system wind resources viable in such high quantity in MISO South, especially by 2032.  The RRF wind resources are a significant departure from Future 1, 2 and 3.  Future 2 contained only 489 MW of RRF wind resources in MISO South.  Future 2A contains ~9.5 GW of RRF wind resources – a nearly 20-fold increase.  Adding the RRF wind resources to the Entergy plans (the “committed resources”) creates a massive wind resource fleet build-out.  Indeed, with the RRF wind resources, MISO proposes to add more wind in MISO South (26,333 MW[2]) than utility scale solar in the same region (25,584 MW) over the next 20 years.  MISO should consider significantly reducing the RRF wind resources in MISO South, especially in PY10, to create a more realistic resource fleet evolution over the next 20 years. 

Off-shore Wind Capacity Additions

MISO has sited 5,000 MW of offshore wind as “committed” resources in Louisiana in PY15, presumably representing the Louisiana Governor’s goal to develop 5GW of offshore wind in the Gulf of Mexico by 2035.[3]  Entergy notes that the achievability of the Governor’s goal will depend on the economic viability of developing these resources, which MISO's assumptions do not consider.  Entergy believes the offshore wind assumption should consider the economics of this resource when comparing the share of the resource mix that is reasonable to assume will be procured to serve load relative to other zero-carbon resource options.  To ignore the impact of economics on the attainability of this goal is not a realistic approach to forecasting the future resource mix for the purposes of a large-scale transmission planning study.

As noted by BOEM in its report on Offshore Renewable Energy Technologies in the Gulf of Mexico, there are significant gaps in both cost and technology between offshore wind and other potential energy resources[4] for Current and projected future costs  of offshore wind, which are significantly higher than onshore wind and should be differentiated in MISO’s EGEAS inputs.  As noted above Entergy estimates the approximate Installed Capital Cost of onshore wind at ~$1,500/kW and offshore wind at ~$3,600/kW; therefore offshore wind at the scale MISO proposes may be ~$10 B more costly than an onshore installation of the same scale , illustrating the importance of both distinguishing the cost of Off-Shore Wind and On-Shore wind when forecasting a resource mix that is intended to represent future resource development.  Entergy may support a smaller application of wind offshore (up to 500 MW) in the study models to represent state policy objectives, but it is premature and unsupportable to assume tens of billions in offshore wind investment when substantially less expensive alternatives are available.

Wind & Solar Future Resource Siting

Many of the initially proposed solar and wind resource sites are in densely populated areas of MISO South where adequate land is not available for utility-scale wind development.  The Siting Spreadsheet contains many recommendations for moving wind out of sites with inadequate available land and urban areas and into areas more suitable for these types of resources.  Generally, if on-system wind does materialize in our region it will likely be in the Mississippi Delta region, central/north Louisiana Delta, or east/north Arkansas.

A significant portion of future Entergy wind resources are likely to come from outside of the MISO region.  Entergy recommends modeling 50-67% of wind resources assigned to Entergy in the SPP area.  Importing wind from west of our footprint is likely to provide the least cost, highest capacity factor solution in the foreseeable future.

Planned Solar Resource Siting

Entergy has provided recommended siting adjustments for solar plants in the Siting Spreadsheet.  Generally, sites for solar plants should be selected where land can be reasonably assumed to be available to develop them.  A solar plant requires between 5-10 acres per MW.  Some sites in the preliminary siting documentation were in densely populated areas, marshland areas or in mountainous areas.  The recommended sites avoid these problematic areas that are ill-suited to solar development.

Retirements Assumptions

MISO F2A deactivation assumptions generally align with current Entergy assumptions.  However, there are two notable units that Entergy requests for the retirement dates to be changed:  Ninemile 5 and Sabine 5.  Due to the critical nature of both resources (DSG and SETEX resources), Entergy Louisiana and Entergy Texas are preparing these units to remain in-service well into the 2030’s.  We recommend replacing the PY5 deactivation assumption with PY15 for both units

Planned Gas Resource Siting

Consistent with the MISO siting methodology, brownfield sites should be given priority over greenfield sites for future gas resources.  Many of the future gas resources, all of which are “committed” resources, align with deactivations.  We provided replacement sites for many greenfield sites that have resources deactivate recently relative to the study year.  See Siting Spreadsheet for list of recommended sites for future gas resources.

Demand Response Resource Siting

Entergy has provided recommended siting adjustments for Demand Response in the Siting Spreadsheet.  Generally, sites for demand response should be selected where load is available to be reduced.  Most sites in the preliminary siting documentation were on substations that do not have load or load that is available to be reduced, such as a power plant auxiliary load.  The recommended sites avoid these problematic areas in which assuming substantial Demand Response is unreasonable.

The Siting Spreadsheet seeks to provide the best locations for all the resources in the preliminary siting.  However, the recommended off-system wind adjustment may not e represented in the spreadsheet, nor are other resource mix changes.  Entergy urges MISO to incorporate the suggested off-system wind and resource mix changes.  Correcting the RRF and siting issues is essential to Entergy’s confidence in the business case for, and ability to support, projects resulting from use of the F2A model.

Feedback from the Mississippi Public Service Commission was submitted via email to Stakeholder Relations.

ATC appreciates MISO's work on the LRTP Futures Update and generation expansion siting process.  After reviewing the proposed expansion siting, ATC has the following observations and comments.

• Currently in Wisconsin there are 8,645 MW of solar in the MISO queue.  In the LRTP 20-year expansion plan, EGEAS is only finding 5,570MW of solar.  While we can assume not everything in the current MISO queue will be constructed, ATC questions whether MISO should assume more solar siting to reflect trends in solar development in Wisconsin.
• Correspondingly, wind development in the MISO queue is only around 1,222 MW.  However, the MISO EGEAS model finds a need for over 6,000 MW of wind in a 20-year timeframe.  In general, trends for wind development in Wisconsin appear to be much lower than what the MISO EGEAS model finds.  ATC suggests more alignment between wind development trends and MISO EGEAS plan.
• MISO also identifies Solar Hybrid as a resource type.  Is this resource a blend of solar and battery, and what percentage ratio is that?
• Currently there is 1,115 MW of natural gas units in the 2022 DPP study cycle in the ATC footprint.  The MISO EGEAS results don’t have any development of natural gas in Wisconsin until the 20-year model.  ATC thinks these units should be pulled forward and aligned with resources in the MISO queue.
• ATC suggest that MISO perform a check on planning reserve margin by local resource zone to reflect what will be required for resource adequacy throughout the study.
• Relative to the MISO queue, the amount of battery resources sited in the first 10-years of the study appears to be less than what is seeking development today.  Specifically, these are seeking development as replacement and supplemental surplus resources and MISO should account for that.

ITC appreciates the opportunity to provide feedback on the F2A siting process. The updated renewable energy additions are a welcome sight as the clean energy aspirations across this industry continue to grow. We look forward to working together throughout the LRTP process.

 As we reviewed the bus level siting in Michigan, we have concerns with the utility scale wind, solar, and storage siting in Southeast Michigan, specifically Oakland, Wayne, and Macomb counties. These areas are highly developed and scattered with prized state & recreational parks. We do not specify bus alternatives, but good candidates could be found in te Michigan Thumb Region and along the Southern parts of Michigan between Palisades and Monroe substations. We also identified a handful of committed units with bus siting that needs to be corrected. Additional detail will be submitted via the siting workbook.

 For Iowa, MISO should also use the current active queued generation as the guiding basis for siting some RRF generation.  The queue is a strong indicator of where each type of resource is likely to be viable for siting and construction. With a form of site control being required to enter the queue, it helps demonstrate that there is some amount of local landowner support for projects to be constructed in an area. 

For example, there is a large amount of RRF resources in the area southwest of the Des Moines Metro (Madison, Dallas, Polk, and Warren counties) but there are not many requests here in the current MISO queue, likely due to local opposition to such projects.  Conversely, there is not much RRF generation in the area between Marshalltown and Cedar Rapids areas (Marshall, Tama, and Benton counties) but there are current queue requests in this area which will be supported the approved Tranche 1 projects that will be built through this area of the state.  In addition, the northeast Iowa area has several requests currently in the queue, yet MISO has no proposed RRF generation in that portion of the state.

Thanks,

ITC Planning

GRE supports the MISO LRTP effort to address the rapid and ongoing generation portfolio transition reliably and efficiently. The LRTP along with the wider Reliability Imperative help meet the Minnesota clean energy standards and GRE policy goals.

Thank you for providing initial resource expansion and siting details as this helps foster stakeholder review and feedback early in the futures and model development process.

•     GRE supports the added scope to validate energy adequacy in the MISO footprint of the non-chronological EGEAS expansion results with a chronological tool (PROMOD).

•     From the F2A retirements spreadsheet provided with the March 8^th PAC meeting materials and the LRTP T2 Workshop #2 preliminary Future 2A siting spreadsheet of resource additions, there are some inconsistent generator names and siting information and GRE has some general comments on RRF generator siting.

• MISO’s draft resource siting includes approximately 3.8 GW of natural gas generation within Minnesota. Given the MN carbon free by 2040 legislation, it’s unlikely new natural gas generation will be constructed, even as a bridge technology. While some dispatchable generation will be required to maintain energy adequacy, this NG generation should either be replaced with existing carbon free technologies (e.g. battery storage) in the near-term, or emerging technologies such as green gas, hydrogen, pumped hydro or small modular nuclear additions in the tail-end of the study period.
• Almost eight GW of wind generation is sited in the NW Minnesota region by 2042. What is the basis for this assumption? There has been minimal wind development interest in that area as seen in the MISO generation queue.
  • The actual DPP22 queue amounts in NE MN consist of just three proposed interconnections:
    • 68 MW solar/battery hybrid resource at Badoura
    • 300 MW battery at Arrowhead,  
    • 325 MW hybrid resource at Arrowhead
• Several large wind units are modeled at buses geographically located in the MN Twin Cities metro area which doesn’t seem reasonable. Is MISO assuming the use of supplemental interconnection at these locations, including:
  • 950 MW at the Aldrich (Xcel) bus 603053 in Minneapolis
  • 460 MW at the Riverside (Xcel) bus 603099 in Minneapolis
  • 850 MW at Red Rock (Xcel) bus 601023
• IMPORTANT: There are several spreadsheet errors throughout MISO where generators have the wrong information as denoted in the examples below. Did MISO have some formatting errors or an inadvertent Excel column shift in the spreadsheet that was provided at the LRTP workshop? The spreadsheet that was provided did NOT have the Bus# column included in the original filter. More examples could be provided. It seems to be a common theme that new committed units are not sited at the right locations and a few examples are shown here:
  • The 400 MW Discovery Wind farm should be sited at Coal Creek and its output be restricted to using the CUDC line. The spreadsheet showed it as sited at Cedar Mountain (615643)
  • Spiritwood is shown as sited at Riverview (615664) which is in MN when the existing unit is in ND. Spiritwood is also duplicated in the model as the retirement file does not retire “Spiritwood Energy:1” and a new “Spiritwood Energy:1CC” is added. Is the CC version of Spiritwood meant to be something different than the existing plant in ND?
  • Boswell 4 is shown as repowered as a CC. This repower is sited at Iron Range instead of  at the existing Boswell bus
  • The Three Waters wind unit is correctly listed in the GRE area but also listed in Texas/LRZ 9 and sited at a corresponding bus in Texas (334085). The Three Waters plant is supposed to be a surplus interconnection with GRE’s Lakefield NG plant.
  • Two other surplus interconnection units (Timberwolf and Dodge County) are incorrectly sited at Benton County and Dickinson respectively when they should have been sited at Pleasant Valley.
  • There is a Plum Creek wind farm (400 MW) sited Quarry. Online searches find a 414 MW Plum Creek project filing that is supposed to be in Cottonwood, Murray, and Redwood counties.
  • MISO has sited a 527 MW CC unit (J732) at Arrowhead. It was our understanding that this unit was intended to represent the future Nemadji NG plant. This unit is not listed to be retired by the 2042 model year. In addition, the MISO preliminary siting includes two new units named “Nemadji Trail Energy Center DPC” and “Nemadji Trail Energy Center MP” sited at Genoa and Riverton respectively. Are these two units different than the planned Nemadji plant? The original plan was for the Nemadji plant to tap the Arrowhead-Stone Lake 345 kV line.
  • Three coal units in Illinois were not listed as retiring by 2042. These are Dallman 4 and Prairie State 1 & 2. The continued inclusion of these units seems counter to Illinois’ CEJA legislation.
  • Currently the new North Dakota generation siting is concentrated in the eastern portion of the state. GRE would suggest greater diversity in siting to better reflect the strong renewable resource potential in central and western North Dakota.

•    GRE urges MISO to consider including LRTP T2 transmission in North Dakota to connect the present MISO islands in ND. By providing contract path to these islands and connecting them with greater MISO transmission system, MISO generation interconnections could occur there without being subject to transmission rate pancaking

•     Currently RRF generation siting in southeastern MN is highly concentrated to a few buses on the Minnesota / Iowa border. GRE would suggest MISO provide greater reliance on the Generator Interconnection Queue for guidance on RRF generation siting.

•     Include more variations of storage battery types other than just 4-hour duration. Storage technology will improve to include various duration capabilities to address different market services. For dispatchability benefits, a pumped hydro project on the Iron Range could be included in the resource expansion.

The Environmental Sector appreciates the opportunity to submit this set of feedback regarding the preliminary Future 2A siting results. Updating the MISO Futures is a vitally important practice to ensure that transmission planning occurs in a timely fashion with the most up-to-date information available. We applaud MISO’s efforts to keep the Futures updated, and it appears the Environmental Sector’s December 2022 comments were widely accepted.  

A new analysis from the National Renewable Energy Lab evaluated the impacts of the federal Inflation Reduction Act (IRA) and the Bipartisan Infrastructure Law (BIL). The analysis found that, “Clean electricity shares could increase substantially with IRA and BIL, rising from 41% in 2022 to a range of 71%–90% of total generation by 2030, across the range of scenarios considering uncertainties in future technology costs, fuel prices, policy impacts, and deployment constraints.” NREL’s study provides an independent analysis that underscores and supports MISO’s revision of the Futures and the anticipated high levels of clean energy additions over the next 20 years. 

Future 2A Retirements Data

MISO provided stakeholders with the modeled retirement dates associated with existing generation facilities in the footprint (“MISO F2A Installed Capacity Additions and Retirements (GW)*”). Specific data regarding individual unit retirements are also available (“20230308 PAC Item 08a MISO F2A Retirements.xlsx”) at the PAC on March 8, 2023. While we understand that this specific feedback request did not include all of those data, we feel it is important to include a discussion regarding the retirement assumptions.The Environmental Sector requests that MISO continue to use the most up-to-date information regarding retirement assumptions and provide a comparison of Future 2A proposed retirement analysis dates with the previous Future 1, 2, and 3 assumptions (“Series 1”) and denote any changes between the two data sets (Series 1 versus Series 2).

For example, in the Future 2A retirement data, some portions of the Independence 1 and 2 coal-fired power plants located in Arkansas are listed as retired within the 5 year time horizon, but listed as an “Unknown LRZ 08” resource. Independence 1 and 2 are jointly owned by Arkansas Electric Cooperative Corp. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The portions selected to retire within the 5 year window add up to 1,009 MW of the 1,663 MW listed in the MISO retirement worksheets, with the remaining 654 MW retiring within the 10 year window. By court order, Independence 1 and 2 are required to close by December 31, 2030. In the Series 1 Futures (Future 1, 2, 3), Independence 1 and 2 were all assumed retired by the Year 10 window. However, in this Series of Futures, we recommend that all of Independence 1 and 2 should be included in the 5 year window for retirement. 

The White Bluff units 1 and 2 coal-fired power plants located in Arkansas are slated for retirement by December 31, 2028 by the same court order; however, in the current retirement model for Future 2A, those units are not slated for retirement until the Year 10 study window. Those two units account for 1,647 MW of nameplate capacity. The Series 1 Futures had White Bluff 1 and 2 retiring in the 5 year window for Future 2 and Future 3, and only in Future 1 was White Bluff considered in the Year 10 retirement window. All of White Bluff 1 and 2 should be included in the 5 year window for retirement, given its earlier retirement timeline compared to Independence 1 and 2. 

As a part of scenario-based planning, Entergy’s various IRPs (in Arkansas and Mississippi, for example) include scenarios for earlier retirement for both White Bluff and Independence coal-fired generation, within the 5 year window. Entergy Arkansas noted, “The primary driver for the next significant capacity deficit after 2025 will coincide with the timing of the cease-to-use coal (“CTUC”) efforts at White Bluff and Independence. That timing will be no later than 2028 for White Bluff and 2030 for Independence but could be sooner.” In keeping with scenario based planning practices, it would make sense to include the “could be sooner” provision regarding both Independence and White Bluff in Future 2A and eventually Future 3A. 

The retirement assumptions may also need to be revisited for Indiana. For example, F B Culley:3 is shown as "out of study period" for all futures. CenterPoint's latest IRP slides (slide 46) shows under every "Draft Optimized Portfolio" that CenterPoint would retire the unit in 2029 - well before the end of the Futures study period. AES Indiana (or, Indianapolis Power and Light) is converting its coal-fired Petersburg units 3-4 (1,052 MW) to natural gas steam (not a CC, not a CT) in 2025, and should be reflected as such in the data. 

Additionally, the retirement data for Future 2A also includes a number of generic units by generation technology types including CC (combined cycle natural gas), CT (combustion turbines), DGPV (distributed generation photovoltaics), Hybrid, IC Gas (internal combustion), LIBAT (presumably lithium-ion batteries), PV, and Wind. The generic units appear to be new units that are added at some point over the 20 year horizon that would then be retired at a later date beyond the study horizon. In effect, the generic units appear to be some level of generator additions included in the retirements data set. Slide 5 of the March 10 presentation regarding this topic shows additions to add up to 333 GW; however, the retirement data set for the new generic units additions (provided to the PAC on March 8, 2023) for all technology types adds up to only approximately 100 GW, and the total data set amounts to 246.6 GW of capacity that exists “Out of Study Period”. Perhaps the difference between the two data summaries is what is manually provided to the model (the 100 GW in the retirement model for new units, and 146 GW of existing units) versus what is model selected (the remainder, or 233 GW). If so, the Environmental Sector would appreciate some clarification.

It appears that DGPV unit additions are severely underrepresented in the “retirements” data set (provided to the PAC on March 8), accounting for only 24.7 MW in the entire “retirements” dataset, and all located within Southern Indiana Gas & Electric’s territory. DR also appears to be underrepresented, accounting for approximately 4.6 GW worth of resources.

Additionally, the retirement spreadsheet provided to the PAC on March 8, 2023 does not include the technology type of the existing (named) generation units assumed to be retired over the next 20 years. It would be difficult to match existing retirement assumptions with fuel type without manually designating each generator type. The Environmental Sector requests that the retirement data be provided in a fashion so that stakeholders can re-create Slide 5 of the Future 2A Expansion & Preliminary Siting presentation.

Future 2A Additions Data

The Environmental Sector evaluated the Future 2A capacity additions based on the quantities of additions, the timing of such additions, and finally, location. The data were provided at the LRTP Workshop on March 10, 2023 (“20230310 LRTP Workshop Item 02 MISO Preliminary Future 2A Siting.xlsx”). At a high level, the resource additions appear to be fairly reasonable; however, upon closer inspection, there appear to be a number of disjointed components of the Future 2A additions that need to be remedied. 

Wind Resources

For wind, Future 2A adds 18 GW in Y5, 58 GW in Y10, 43.5 GW in Y15, and 26 GW in Y20 for a total addition of roughly 146 GW by 2042. There are currently 24,750 MW of wind generation resources in the MISO queue. Broadly, the ramp-up of wind additions tracks well with the implementation of the Inflation Reduction Act, given that federal tax credits have been extended through the end of the 2020s. 

The state-by-state breakdown of wind resources appears to be fairly reasonable; except for Louisiana, Louisiana adds over 15 GW of new wind resources, while solar resources reach just 10 GW. Of the wind from Future 2A, 9.6 GW are “committed” in Louisiana, mostly in Y20, and 5.9 GW are RRF model-built resources, almost entirely in Y10. While the offshore wind opportunities for Louisiana are quite high, offshore wind appears to be just 2.5 GW worth of Louisiana’s total wind capacity within the modeled 15 GW; thus, the remainder of the wind resources in Louisiana are assumed to be in-state land-based wind, a high amount given the amount of wind in the Louisiana queue currently. 

Some wind additions provided in the model data seem highly unlikely to come to fruition. For example, some 3.5 GW of wind resources are added to St. Charles Parish, Louisiana in the dataset. St. Charles Parish is located just to the west of New Orleans, and is heavily defined by local swampland with few opportunities for development. Several other Parishes contain similar land use constraints, but contain high quantities of wind development per the Future 2A dataset. Of the 34 GW of resources currently in the queue for Louisiana, only 230 MW are wind, and zero megawatts of any resource are being evaluated for St. Charles Parish, likely due to the land use constraints. It appears that MISO may be relying on Entergy Louisiana’s draft IRP Portfolio 2 for the quantity of wind added; however, that Portfolio has been recognized as unlikely in the stakeholder process and, regrettably, that portfolio does not include any offshore wind. Regarding onshore wind in Louisiana, the Environmental Sector recommends MISO 1) maintain the offshore wind component and/or increase the amount, 2) allow wind imports from out-of-region (like SPP), and/or 3) reduce the amount of wind assumed in the model due to land use constraints and replace those resources with hybrid resources. Finally, we encourage MISO to provide clear explanations for the methodologies and source documentation regarding quantities of all resources across the footprint. 

Regarding offshore wind specifically, the Environmental Sector requested offshore wind be included in Future 2A in our December 2022 comments and we are pleased MISO is including offshore wind, particularly for the Gulf of Mexico. A National Renewable Energy Lab report highlights the potential for offshore wind in the Gulf of Mexico and supports its inclusion in the Series 2 Futures updates. However, we object to MISO’s stated plan to use onshore wind generation profile data to model the proposed offshore wind generation near Texas and Louisiana. Offshore wind’s generation profile is unique and distinct from onshore wind resources. Offshore wind resources typically provide significantly higher capacity values compared to onshore wind due to the diurnal sea breeze effect. This bears out in ERCOT’s higher capacity evaluation for coastal onshore wind projects that share similar characteristics to offshore wind projects. The National Renewable Energy Lab’s Wind Prospector toolkit provides sub-hourly generation models for offshore wind near Southwest Louisiana and Southeast Texas for multiple years (1.3 gigabyte download available). The Bureau of Ocean Energy Management (BOEM, the federal agency in charge of offshore wind lease sales) includes NREL data for hourly wind speed values in the Gulf of Mexico, as well as other regions. The data are available for download. We recommend MISO use an offshore wind profile for offshore wind projects. 

Further on offshore wind, the two points of interconnection might be reasonable; however, both are listed as 230kV connections. We recommend MISO evaluate whether the interconnections should be relocated to the nearby 500kV system. 

Solar Resources

For solar, Future 2A adds 37.5 GW in Y5, 28 GW in Y10, 20 GW in Y15, and 21 GW in Y20 for a total addition of roughly 107 GW by 2042. There are currently 141,814 MW of solar generation resources in the MISO queue. Broadly, the ramp-up of solar additions tracks well with the implementation of the Inflation Reduction Act, given that federal tax credits have been extended through the end of the 2020s. 

DGPV 

While the data provided are not clear, it appears that roughly 17 GW of solar is designated as distributed generation (DGPV) while nearly 90 GW are designated for utility-scale. Most of Indiana’s DGPV (1.3 GW of 2.1 GW) is added in Y5, while most of Louisiana’s DGPV (1.8 GW of 2.1 GW) is added after Y15. Most states add zero MW of DGPV in Y5, including Arkansas, Illinois, Iowa, Louisiana, Michigan, Mississippi, Montana, North Dakota, Texas and Wisconsin. In fact, Y15 has the highest level of DPGV additions compared to any of the other years, beyond the time horizon for the Inflation Reduction Act tax credits. This is an unrealistic set of assumptions that no DGPV would be added for most of MISO’s states over the next five years. 

Specifically regarding individual county levels of DGPV, the Environmental Sector recommends MISO conduct a “gut check” with regards to the proposed quantities deployed. For instance, in Indiana the highest level of DGPV deployment is slated for Lake County (550 MW) while Marion County, the state’s most populous county, is slated for just 200 MW of DGPV deployment. Indiana currently has a total of 192 MW of net metering solar capacity currently installed, which would likely be designated as DGPV. However, net metering ended effective July 1, 2022. Based on the policy change, the 1.2 GW of DGPV in Indiana seems overly ambitious, especially within the next 5 years (Y5).  In Missouri, Boone County has the highest level of DGPV (500 MW) while being the state’s 8th most populous county, while St. Louis County has less DGPV (350 MW), but nearly six times more people. MISO should provide narrative explanations for the DGPV build out assumptions and/or update DGPV siting and build out assumptions. 

Broadly, it appears that DGPV are provided to the model in 50 MW increments. We recommend that MISO consider adding smaller amounts of DGPV in a more evenly distributed fashion. 

Utility-Scale PV

The highest levels of utility-scale solar additions include Michigan (17 GW), Indiana (12 GW), and Minnesota (11 GW). Louisiana’s utility-scale solar additions amount to nearly 8 GW. All other states have less than 6.2 GW of solar additions over 20 years. Kentucky (1.1 GW) and South Dakota (0.8 GW) are the states with the least solar additions over the Future 2A time horizon. North Dakota adds nearly 2.5 GW, or three times as much solar as South Dakota, which seems like an unusual distribution. Comparably, Louisiana’s 8 GW seems low given that state’s high level of solar irradiance and southerly location. The Environmental Sector recommends that MISO cross-compare the proposed solar build-out with the current generation interconnection queue locations, and ensure that land use considerations are reasonably incorporated (e.g. sensitive areas and areas with little land availability should be de-prioritized). 

Hybrid Resources

For solar hybrid resources, Future 2A adds 1.2 GW in Y5, 3.3 GW in Y10, 3.5 GW in Y15, and 2 GW in Y20 for a total addition of roughly 9.8 GW by 2042. There are currently 47,053 MW of hybrid generation resources in the MISO queue. In Future 2A, no new hybrid resources are added in Y5, with the exception of Wisconsin (1.1 GW) and Indiana (75 MW). No hybrid resources are added in Iowa, Kentucky, Missouri, Montana, nor North Dakota until Y15, and even then, all those states add less than 215 MW over the next fifteen years. Louisiana only adds 50 MW of hybrid resources in Y10, and then none at any other time. Mississippi and Montana add no hybrid resources over the next 20 years, which seems like a highly unlikely situation. The Environmental Sector recommends that MISO cross-compare the proposed hybrid build-out with the current generation interconnection queue locations, and significantly increase the amount of hybrid additions over the next 20 years, especially in Y5. 

Battery Storage Resources

For battery storage resources, Future 2A adds 0.5 GW in Y5, 3.5 GW in Y10, 13 GW in Y15, and 10.5 GW in Y20 for a total addition of roughly 27.9 GW by 2042. Nearly 20 GW of those resources were identified as RRF resources. There are currently 46,021 MW of battery storage generation resources in the MISO queue. For Y5, only 552 MW of battery resource additions are added, mostly in Michigan (182 MW) and Wisconsin (175 MW). Overall, MISO’s expansion of battery storage seems to fall short of expectations and we encourage MISO to revisit the storage deployment assessment, just as we recommended in our December 2022 comments. 

Michigan has the highest amount of battery storage additions over the next 20 years, with just over 5 GW added, or almost 20% of all batteries deployed. Indiana has nearly 4 GW deployed, and Wisconsin and Minnesota each having 2.5 GW and 2.2 GW of batteries deployed, respectively. 

In the data, some LBA/Areas seem disjointed from where proposed battery deployments exist. For example, several LBA Entergy New Orleans battery resources are deployed in Mississippi. For Entergy Mississippi, some of the battery resources are deployed in Louisiana, and in areas not close to the Mississippi border (like Calcasieu Parish). While we generally support optimizing generation, regardless of geographic location, it seems unusual that batteries for an LBA would be sited far away from its natural footprint. We request some insight into why batteries may be sited far away from their intended customers.

The Environmental Sector recommends that MISO develop a portfolio of distributed battery resources, similar to the DGPV resources. Given the likelihood that Order 2222 will expand distributed battery deployment, alongside the Inflation Reduction Act benefits, now is the time to incorporate these resources for planning purposes. We suggest these resources be designated as LITDG (for distributed generation lithium batteries) and be deployed in similar fashion to the DGPV resources. 

Electric Vehicles

Currently, the MISO data does not clarify assumptions regarding electric vehicle (EV) adoption rates and dispatchability. Like these comments, EV’s may fit somewhere between a DGLIT resource capable of being dispatched in a vehicle-to-grid fashion in some states, or as a demand response resource where EV charging is directly controlled down as an aggregated resource. With the implementation of Order 2222, EV’s will become a growing source of controllable, dispatchable load and/or generation. The Environmental Sector recommends MISO include EV growth as distributed energy resources after Order 2222 implementation, as in, by Y5. 

Demand Response

For demand response resources, Future 2A adds 9.8 GW in Y5, 183 MW in Y10, 315 MW in Y15, and 181 MW in Y20 for a total addition of roughly 10.5 GW by 2042. The largest states with DR resources include Minnesota (2.7 GW), Michigan (2 GW), Indiana (1.1 GW) and Wisconsin (0.8 GW). All other states have somewhere between 293 MW - 648 MW worth of DR resources. The anemic additions of new DR over planning years Y10, Y15, and Y20 is puzzling, given the likelihood that Order 2222 will enable greater demand response programs and that demand response resources will become increasingly valuable as renewable energy penetration levels increase. MISO’s proposed implementation date of Order 2222 is 2029 and so one would expect the DR Resources to increase more dramatically after Y5. It is exceptionally bizarre that a state like Louisiana, which has significant industrial load, would have zero new DR capacity past Y5, and only accounts for 340 MW of DR in Future 2A. As green hydrogen production increases across MISO, new large loads may be added that are capable of providing demand response. Demand response is an important tool for ensuring system reliability and may be more highly valued for its effective capacity contributions over the next 20 years. We recommend MISO evaluate DR potential and include higher levels of DR appropriately across the footprint. 

Natural Gas Resources

There are currently 6,955 MW of natural gas generation resources in the MISO queue. Future 2A adds 20.5 GW of new gas resources over the next 20 years including a mix of both CT and CC units. Few natural gas RRF CT and CC units are added. An additional 542 MW of “other” gas resources are added that are made up mostly of reciprocating engine (RICE) facilities. RICE units are only added in Entergy, Consumers, Iowa and Wisconsin territories and none are RRF units, highlighting the limited deployment of those facilities. It appears that potentially all states add some level of new gas units over the next 20 years, with Minnesota (3.7 GW), Michigan (2.9 GW), Indiana (2.6 GW), Illinois (2.5 GW), and Louisiana (2.4 GW) adding the most. The Environmental Sector requests clarity whether these resources are anticipated to include any level of carbon capture sequestration (CCS) or hydrogen burning capability. 

We encourage MISO to evaluate if these new facilities have gas pipeline capacity available and/or to locate these new facilities at retiring facility locations to re-use the existing points of interconnection. 

Hydrogen Resources

Notably absent from the Future 2A discussion is the treatment of new hydrogen-fueled generation resources, such as thermal combustion, as well as new hydrogen load created from a growing electrolysis industry. It may also be worth looking at how siting may differ depending on whether hydrogen electrolyzers are co-located with load or near generating resources. Considering the difficulty in transforming existing gas infrastructure into hydrogen infrastructure, it is perhaps likely that the former is the most likely scenario. The Environmental Sector would invite a discussion about including hydrogen generation resources, as well as new hydrogen electrolyzers as load growth. 

HVDC

Several proposed HVDC resources should also be included in Future 2A. For example, there is currently a 1,500 MW interconnection request for an HVDC resource in Mississippi. Also, the Grain Belt Express project would interconnect with MISO to provide 2,500 MW of power and capacity. Both projects would import significant amounts of non-MISO resources into the MISO system. Excluding these resources in an “advanced” portfolio like Future 2A would have a similar system impact to excluding a new nuclear reactor’s worth of energy and capacity - the impact would be huge.  We request that these resources, and any other HVDC resources that may be added, be included in Future 2A. 

Carbon Capture Sequestration/Small Modular Reactor Resources

Notably absent from the Future 2A discussion is information regarding CCS and SMR’s. Coal Creek CCS 1 and 2, for a total of approximately 160 MW, are included for Great River Energy in North Dakota in the Y5 planning year and are listed as an “Other” generator type, as opposed to coal. The Environmental Sector would like clear information regarding CCS and SMR units as potential resources. Potentially in Future 3A, MISO can include its “unicorn” generation technology, the "Low emissions, high capacity factor, dispatchable" facilities discussed at the November 10, 2022 Regional Resource Assessment Workshop. 

Montana

While there are currently no resources in the Montana portion of MISO’s generation interconnection queue, it is highly unusual that Montana only adds 88 MW of gas in Y5 and 49.5 MW of wind in Y15 in Future 2A. We recommend a deeper dive into Montana’s generation mix over the next 20 years. 

Futures 1A, 3A

When MISO first began the “Futures Evolution” discussion, Futures 1, 2, and 3 were discussed simultaneously; where Future 1 was meant to represent a conservative or business-as-usual case and Future 3 was meant to represent the most advanced case. As history has shown, even with the Series 1 of Futures 1, 2, and 3, our forecasts in the future have rapidly changed - Future 2 now resembles Future 1A, and Future 3 now resembles Future 2A. In our December 2022 comments, the Environmental Sector made several recommendations regarding Future 3A. We request that MISO include an update regarding Future 3A development and engage stakeholders in discussing the scoping of that future sooner rather than later. 

The purpose of scenario-based planning is to provide “bookends” of potential futures where transmission proposals are tested across multiple futures. Unfortunately, MISO seems to be stepping away from using the full breadth of the bookends and is instead relying on individual futures for each new “tranche” of the Long Range Transmission Planning process. Not only does this provide a much less robust set of analysis for each transmission line, it also potentially causes a lag in transmission planning that we do not have the luxury in entertaining anymore. As envisioned, using all three Futures has been the hallmark of smart planning practices, as recognized by the Federal Energy Regulatory Commission’s Notice of Proposed Rulemaking regarding regional (and soon, interregional) transmission planning. We are concerned that MISO and the stakeholders at large are stepping away from scenario based planning practices and we encourage the use of all Futures simultaneously, as originally envisioned five years ago. 

The Environmental Sector appreciates MISO’s willingness to share data from Future 2A on both the retirement and additions side of the generation equations in the newly developed "Future Planning Scenarios" webpage. Stakeholders are able to provide much more robust commentary when data are easily shared and available. We request that MISO also provide the retirement and additions data of Future 1A in similar fashion to the data provided regarding Future 2A to create continuity of information sharing on the "Future Planning Scenarios" webpage, and prepare to do the same for Future 3A.