Draft MTEP24 Report, Appendices Feedback

Page 1-7           May want to highlight other interregional planning efforts other than JTIQ.

Page 1-13         Include other interconnected areas such as TVA and Ontario.

Page 2-10         Explain how MISO incorporated chronological-based models and transmission into Tranche 2.1 planning.

Page 2-10         Explain how MISO incorporated chronological-based models and transmission into Tranche 2.1 planning.

Page 2-38        Further explain “100% renewable penetration”.  Is this at low load with high renewable output?

Page 2-137      Explain why Region 4 benefits are negative.

On behalf of the End Use Sector, I submitted substantive feedback via an email with pdf attachment to stakeholder relations since the feedback included figures which do not show up using the feedback tool.  I have requested that the End Use Sector's comments be posted with other public and substantive feedback (PAC material, Board of Directors material) regarding the Draft MTEP 2024 Report.

Regards,

Kavita Maini

End Use Sector, PAC Representative

kmaini@wi.rr.com

TO:                     MISO Stakeholder Relations
FROM:               ITC Holdings

ITC Holdings (ITC) thanks MISO for the opportunity to provide feedback on the Draft MTEP24 Report, which was recently discussed during an October 1, 2024, special meeting of the Planning Advisory Committee.  ITC Holdings provides the following comments for MISO’s consideration:

I.                   Draft MTEP Chapter 1 – Transmission Planning Overview

                      ITC supports MISO’s Draft MTEP24 Transmission Portfolio and accompanying report.  MISO’s Order No. 890- and 1000- compliant MTEP planning process is an open, transparent, and time-tested process.  ITC recognizes the importance of the MTEP planning process in addressing transmission issues, and as a participant, views the MTEP planning process as a critical component of MISO’s Transmission Evolution initiative, which is one of the four prongs of MISO’s Reliability Imperative. 

II.                  Draft MTEP Chapter 2 – Regional Long Range Transmission Planning

                      ITC supports MISO’s Long Range Transmission Planning work as another critical component of MISO’s Transmission Evolution initiative and, in turn, a material contribution to solving MISO’s Reliability Imperative.  In particular, ITC supports the final $21.8B LRTP Tranche 2.1 portfolio of projects included within Draft MTEP24 and Appendix A.  MISO has extensively collaborated with stakeholders for approximately two years to finalize this portfolio and demonstrate its benefits.  Specifically:

• ITC supports MISO’s Futures-based planning approach, including MISO’s approach for resource expansion and resource siting. 
• ITC supports the final Tranche 2.1 portfolio developed through application of MISO’s planning process and in collaboration with stakeholders.  LRTP Tranche 2.1 is a visionary and necessary approach to solving MISO’s Reliability Imperative.
• MISO collaboratively developed and socialized nine benefit metrics with its stakeholders over an approximate one-year period.
• MISO utilized nine-benefit metrics to develop a business case that is conservative and demonstrates that benefits of the LRTP Tranche 2.1 portfolio are likely to be realized and are broadly and equitably distributed throughout the MISO Midwest subregion (with an aggregate, conservative benefit-cost ratio of 1.8).[1]
  • ITC supports MISO’s approach to developing a reference case/change case to measure benefits for LRTP Tranche 2.1, as referenced throughout Chapter 2.  
  • MISO’s methodology to compute benefits for the Mitigation of Reliability Issues and Reduce Risks from Extreme Weather Impacts are appropriate, but quite conservative.  The industry has learned from past experiences that significant load shedding can occur resulting in loss of life from even a single major event.  There is no doubt that weather events are only becoming more severe and frequent, significantly increasing the likelihood and impact of major load shedding events.[2]
• LRTP Tranche 2.1 marks a significant step forward in addressing the Reliability Imperative.  However, LRTP Tranche 2.1 does not resolve all the issues presented by Future 2A.  ITC supports MISO moving forward with LRTP Tranche 2.2 soon after LRTP Tranche 2.1 is approved by MISO’s Board of Directors. 

III.                 Draft MTEP24 Chapter 3 – Interregional Planning

                      ITC supports the MISO/SPP Joint Targeted Interconnection Queue (JTIQ) Study and the portfolio of JTIQ projects included in MTEP24 Appendix A.  JTIQ is a proactive, innovative, and collaborative solution to the pressing need for new generation interconnection capacity, especially for renewable resources along that seam.  JTIQ offers a more streamlined and efficient alternative to the traditional Affected System Study process, delivering cost and timing benefits to interconnection customers and supporting the development of a cleaner and more reliable electric grid.  The United States Department of Energy (DOE) similarly recognized these visionary aspects of JTIQ, and announced approval of $464 million of Grid Resilience and Innovation Partnerships (GRIP) funds to help defray the costs of the inaugural JTIQ portfolio.  

                      ITC also supports the MISO-PJM Interregional Transfer Capability Study and the MISO-SPP Interregional Study, both of which were announced by MISO in 2024 but are not expected to yield any results until 2025.  ITC supports MISO’s solutions- oriented planning approach, and its acknowledgement that existing interregional planning processes have been ineffective.  ITC looks forward to collaborating with MISO as these innovative interregional planning efforts progress.

IV.         Draft MTEP Chapter 4 – Local Reliability Planning

ITC supports MISO Board approval of MTEP24’s Local Reliability Projects, which includes 459 new projects in Appendix A representing over $6.7 billion in transmission infrastructure investment.[3]  MISO’s high-profile and portfolio-based and/or interregional-focused planning efforts may sometimes overshadow the day-to-day efforts to maintain the safe, reliable, and cost-effective operation of MISO’s regional grid.  However, MTEP Local Reliability Planning is the “bread and butter” of the annual MTEP, and this annual “bottom-up/top-down” open, transparent, and collaborative planning process is at least of equal importance to MISO’s regional and interregional planning efforts.     

V.          Conclusion

ITC supports Draft MTEP24 and recommends that the Board approve MTEP24 as presented.  ITC appreciates the opportunity to provide these comments to MISO and its stakeholder community.

ENVIRONMENTAL SECTOR’S SUBSTANTIVE COMMENTS

TO THE MTEP24 DRAFT REPORT

Once again, MISO has established its national leadership in regional transmission planning.  The Environmental Sector (“Sector”) applauds the finalization of Tranche 2.1, which is yet another step in both recognizing and enabling the ongoing transformation of the electricity industry.  MISO rightfully points out “The job of the LRTP is to enable a reliable generation fleet as planned by MISO Members and states.” It is not MISO’s job to be a resource planner, and we applaud MISO’s focus on enabling the plans of its member states and load serving entities.

While the Sector fully supports Tranche 2.1, we do have some specific comments and substantive recommendations for the Report.  

Recurring Themes: 

1. Point the Other Way:   When planning 20 years out, MISO must “take” the resources its members and states have in their future plans to prepare the grid to reliably accommodate those resources. However, the draft Report (as well as MISO’s comments at the most recent board meeting and MISO’s 9/13/24 amicus brief to the U.S. Court of Appeals for the DC Circuit objecting to EPA regulations) can be read to blame MISO members, states, and EPA for MISO’s current tight resource adequacy conditions and reliability challenges.  But MISO fails to look in the mirror to identify how its actions and omissions have led to the conditions and challenges it is facing.

Under the Transmission Evolution Section in Chapter 1, MISO could call out any of the following as contributing to the current debacle - and these are just a few of the examples:

• Waiting six years after the first Multi-Value Project portfolio to conduct another long-term planning process and then canceling the Regional Transmission Outlet Study (RTOS) in 2017 and not starting LRTP until 2019;
• Inability to get new generation interconnected to the regional grid;
• Slow/stopped generation interconnection queue processes (though MISO blames the lack of new generation entirely on supply chain and permitting issues);
• Numerous barriers to entry for electricity storage development and operations in MISO; and
• Having insufficient staff to complete regional, interregional, and interconnection planning more quickly.

It would save consumers money and increase reliability if MISO were to solve these problems in a timely manner.

2. MISO Places its Finger on the Scales to Support Fossil-Fuel Generation:

Time and again, MISO states that the region’s resource adequacy and reliability challenges are due to fossil fuel retirements and growing renewables.  (For example: see Retirement of Traditional Resources Ch. 1 p. 4 and Fuel Assurance on p. 5.)  Indeed, at the last board meeting, MISO asked members and states to consider “relaxed renewable/clean energy goals” and to delay retirements of fossil generators.  Rather than asking others to slow down, MISO should speed up what is within MISO’s control to get the following capacity on-line as quickly as possible, including: 

•  New electric storage^[1]
•  New generation through the interconnection queue, and
•  New transmission lines through Tranches 2.2, 3, and 4. 

3. Identify Opportunities, not just Obstacles:  the draft MTEP24 Report focuses on what has stopped progress in the past, but fails to identify the opportunities for the future, such as the following:

• MISO ‘s footprint has some of the best wind resources in the world meaning that MISO’s members have the opportunity to access some of the least expensive wind generation in the world to help drive down consumers’ bills;
• Technologies can increase the capacity of the grid such as installing advanced conductors and wind speed adjusted dynamic line rating; and
• Improvements in storage technology including pilot projects within the MISO footprint of very long duration (150-hour) storage.

We encourage MISO to rewrite portions of the MTEP24 Report to address the issues we have raised in the themes above.

Section-Specific Substantive Comments: 

2.2 The Planning Process

The Futures:   In Tranche 2.1, MISO only used Futures 1A and 2A; but, in Ch. 2 p. 9 MISO touts the futures' ability to "appropriately bookend future uncertainty." MISO failed to adequately bookend the future because it failed to build the models for F3A. Indeed, according to some stakeholders, F3A is even too conservative in some respects.  In all of MISO’s long-range planning efforts, the Futures have been too conservative by the time the planning process has been completed.  For Tranche 2.2, MISO must include a truly aggressive bookend to ensure the grid can accommodate the generation, load, and weather changes that are coming. 

The Benefit Metrics:  MISO underestimates the savings brought by the LRTP lines (presumably to minimize the debate over those calculations).  However, we believe underestimating the savings is a disservice to the public as it misrepresents the full value stream that regional backbone lines bring to MISO’s consumers.  For example, the asset life of a transmission line is 60 years or more; however, MISO relies primarily on the savings received in the first 20 years of a line. 

The following provide examples of underestimated savings within specific metric calculations:  

1.  Mitigation of Reliability Issues - this metric uses the value of lost load (VOLL) to quantify the benefits of avoided load shedding, which is appropriate.  The focus of this metric is on the impact on consumers, and VOLL is our best representation of that value.

We agree that MISO should include both the $3,500 and the $10,000 values for VOLL. While $3,500/MWh is the approved VOLL and MISO must, therefore, use it, MISO is filing its new VOLL ($10,000/MWh) to FERC in Q4 this year. Including the $10,000 VOLL provides context to the board and the public of how this calculation will affect Tranche 2.2.  The Board should note that a VOLL of $10,000/MWh is a more realistic number based on present-day accounting, while the “now-outdated”^[2] $3,500 VOLL is based on such accounting conducted in 2007. Reliance on the $3,500 VOLL–while legally appropriate– leads to a grossly conservative result in this part of the analysis. Finally, although the upcoming FERC filing uses a VOLL of $10,000/MWh, the Board should also note that this is MISO’s “Pricing VOLL,” whereas the “System VOLL” that is fundamental to MISO’s scarcity pricing reforms is based on a VOLL of $35,000/MWh.^[3]

2. Reduced Risks from Extreme Weather Impacts - We appreciate MISO’s recognition of the benefits received by mitigating the impacts of extreme weather, which differ from the benefits of mitigating the reliability failures caused by common contingencies, as captured in the “Mitigation of Reliability Issues” metric.

However, MISO’s calculation of these benefits severely under values the reduction in risk provided by the regional backbone grid during extreme weather events:

1. This metric uses ”14 weather years [2007-21] of load and renewable generation profiles”.  However, we know that the incidents of extreme weather are increasing^[4] and the current metric undoubtedly undercounts this benefit.  For Tranche 2.2, the increasing trend of extreme weather must be captured.^[5] 
2. MISO is assuming events in years 5, 10, 15, and 20. This is likely unreasonably conservative given the increase in frequency of high-impact events over the past decade. Also, given the use of the 7.1 discount rate, staff should provide the same calculations assuming events in year 1, 6, 11, and 16 to better reflect the uncertainty and range of likely benefits to ratepayers.
3. Similar to what is stated above under “Mitigation of Reliability Issues,” this metric uses the current VOLL of $3,500/MWh alongside the VOLL of $10,000/MWh that MISO will be filing at FERC later this year. Since MISO uses its most conservative numbers when publishing its final benefit/cost ratios, we merely mention this to remind the Board that the b/c ratio in this metric and in the Mitigation of Reliability Issues is therefore grossly conservative in that it uses an outdated VOLL based on accounting completed in 2007, not 2024.

3. Avoided Capacity Cost - this metric also uses the same historic 14 weather years and MISO runs hourly simulations “to reflect the probabilities of forced outages, including temperature-dependent correlated outages.”  As noted above, this historic weather data does not reflect current extreme weather trends and will underestimate the number of forced outages and temperature-dependent correlated outages. In other words, it will underestimate the savings created by the increased transfer capabilities from Tranche 2.1
   
   
4.  Decarbonization - 
   1. MISO’s use of $85/ton as the low-end value of decarbonization benefits is inappropriate. The federal social cost of carbon is currently set to $190/ton assuming a 2.0% discount rate.^[6] The use of $85/ton significantly undervalues the assumed benefits of decarbonization across the MISO footprint.
   2. MISO also fails to monetize the other health benefits of reducing air pollution. There is a robust body of scientific research and analysis to justify including avoided public health impacts, yet MISO refuses to do so. MISO’s refusal does not obviate these impacts, and we continue to call on MISO to include public health benefits of avoided pollutants as a benefit metric.  Because MISO does not monetize these other public health benefits derived from reduced air emissions, MISO should use the Minnesota PUC’s carbon cost of $248.67 2024$/metric ton. 

Base Case for Calculating Benefits:  During the stakeholder process, there was considerable debate on how the benefits should be measured when comparing the base case to the change case.  We strongly agree with MISO that the appropriate base case in the economic analysis is the same resource portfolio as in the change case but without the LRTP projects under evaluation. The Future 2A resource expansion was built upon information from the states and LSE’s that are the resource planners in the MISO region and the developers looking to build new resources (e.g. the generator interconnection queue). Developing a new, purely hypothetical counterfactual provides limited, if any, value compared with these robust inputs and should be used only to fill gaps in our existing knowledge. Developing a purely hypothetical counterfactual would marginalize what we do know, ignore long-term planning decisions in IRPs and state laws, and would make the benefit calculations less accurate, not more.

Conclusion:  Again, we appreciate MISO’s work on the MTEP24 report, including the huge effort to plan the Tranche 2.1 portfolio.  We offer these comments to highlight that, while Tranche 2.1 does meet the MVP benefit to cost ratio, the real benefits likely to come from this portfolio will be much higher.  We urge MISO to continue to improve its benefit metrics and futures assumptions. And we reiterate our request for MISO to be more proactive to integrate storage and advanced transmission technologies into its work on transmission planning and markets.

Respectfully submitted on behalf of the Environmental Sector.

Natalie McIntire

Senior Advocate, Sustainable FERC Project

Otter Tail Power Company (Otter Tail) appreciates the opportunity to provide comments on MISO’s Draft MTEP24 report.  While we are generally supportive of the entire draft MTEP24 report, our comments focus specifically on the Long Range Transmission Planning (LRTP) Tranche 2.1 and Joint Targeted Interconnection Queue (JTIQ) Projects. 

For nearly 15 years, MISO has performed long range transmission planning and was the first Regional Transmission Organization to recognize the need for this longer-term planning process.  MISO developed a process that is held up as a model for the entire nation under Order 1920, and MISO continues to fulfill its duty to provide a reliable transmission system to meet the future needs of its members with robust portfolios under the LRTP planning process. Planning for 20 years of transmission needs involves forecasting a number of inputs and working amid uncertainty.  MISO uses future scenarios, which are developed with the opportunity for active engagement by stakeholders.  Otter Tail believes these are reasonable bookend scenarios that produce a least-regrets portfolio of projects to account for those uncertainties.  Otter Tail believes the nine benefit metrics are appropriate, well-defined, and develop a business case that is conservative for Tranche 2.1. We know the LRTP Tranche 2.1 projects will bring additional benefits not quantified by MISO within the metrics analysis and the facilities will continue to bring benefits to the region well beyond the 40-year period quantified by MISO.   We are seeing increasing costs of transmission to meet the future needs of the region, but doing nothing is simply not an option.  MISO’s comprehensive and collaborative LTRP process produces a regional solution that Otter Tail believes is the most cost-effective approach to maintaining a reliable grid and meeting future needs.  Otter Tail fully supports MISO’s LRTP planning process. 

As a stakeholder, Otter Tail provided feedback to MISO numerous times in the futures and portfolio development.  We made suggestions on the alternative siting of future generation as well as on the project alternatives.  The initial Draft Tranche 2.1 portfolio fell short of addressing the needs in the North Dakota, South Dakota, and western Minnesota areas. As part of the alternative’s submission process, Otter Tail submitted projects to address additional needs, along with our analysis to support these projects.  Ultimately, MISO agreed with our identification of additional voltage and thermal constraints that needed to be resolved as part of Tranche 2.1, and they accepted some of our proposals while providing alternate solutions to others.  Otter Tail believes the final MISO Tranche 2.1 portfolio addresses most areas of concern that we had with the initial draft portfolio.   Notably though, MISO Tranche 2.1 does not address all the needs in the Midwest Subregion.  Therefore, Otter Tail supports MISO moving forward on LRTP Tranche 2.2 soon after LRTP Tranche 2.1 is approved. 

Regarding the JTIQ projects, Otter Tail supports the portfolio that resulted from this novel approach to affected systems studies.  The JTIQ planning process provides efficient solutions to address the delays in the current process and targets the constraints that create significant barriers to interconnection of new generation along the seam.

STAKEHOLDER COMMENTS

OF INVENERGY TRANSMISSION LLC

Invenergy Transmission LLC (“Invenergy”) appreciates the opportunity to submit these comments regarding MISO’s proposal to include the Long Range Transmission Planning (LRTP) Tranche 2.1 Portfolio of transmission projects to the MISO Transmission Expansion Plan (“MTEP”) 24.  Consistent with encouragement from MISO to take full advantage of the stakeholder process[1], these comments are largely focused on the “no-harm” analysis memorialized in Chapter 2 of the Draft MTEP24 report under the Refining Solutions and Robustness Testing section.  In addition, these comments also build upon previous comments that Invenergy submitted on May 13, 2022, March 30, 2023, April 3, 2023, May 23, 2023, April 1, 2024, and May 13, 2024, as well as our vocal engagement in all the numerous Planning Advisory Committee meetings and LRTP workshops MISO hosted.

The decision to overlook advanced-stage merchant transmission in the base models have pushed the LRTP portfolio away from the Federal Energy Regulatory Commission (“FERC”) guidance that transmission planning should focus on the most efficient and cost-effective transmission solutions.  In addition, this decision is counter to the Department of Energy (“DOE”) policy encouraging the development and construction of high-voltage lines connecting areas with significant renewable energy resources to load centers.

Invenergy believes there are opportunities for improvement for MTEP to better harmonize LRTP with merchant transmission based on experience from the LRTP Tranche 2.1 process, and Invenergy looks forward to continuing working with MISO to ensure the optimized, cost-efficient transmission that the grid needs and ratepayers can support. 

Feedback on GBX Robustness Testing (i.e. “No-Harm” Analysis)

MISO asserts there is no need to include GBX in the Tranche 2.1 Base Case because MISO will undertake an after-the-fact sensitivity on Tranche 2.1 that includes GBX.  This plan is deficient and short of what is needed to protect ratepayers.

The scope of what MISO studied as a sensitivity for Tranche 2.1 is inadequate.  MISO will assess only whether GBX or other “key projects” will drive reliability issues on the system when their energy flows are added on top of Tranche 2.1.[2]   This will not result in an optimized, lowest cost transmission portfolio.  MISO must instead analyze each project in the Tranche 2.1 Portfolio starting with GBX in the Tranche 2.1 Base Case.  GBX will inject 6.3 TWh annually, years before the Tranche 2.1 Portfolio comes online.  The Tranche 1 Portfolio, which is included in the Tranche 2.1 Base Case, will come online contemporaneously with or after GBX, and GBX will be operational at least three-to-five years before the projects in the Tranche 2 Portfolio.   

The scope must be a re-study or more appropriately an initial study that includes GBX in the Tranche 2.1 Base Case.  MISO has, in effect, undertaken a restudy with its Tranche 2.1 business case assessment, for example, revising Futures 2A, GW shifted to other Zones, and using new metrics to select the Tranche 2.1 Portfolio.  MISO should have included the 6.3 TWh of energy and hundreds of millions of dollars worth of GBX related network upgrades Invenergy has agreed to fund as part of that restudy not only because of the mature state of GBX but because MISO has already acknowledged that it will be putting GBX in its MTEP 25 Base Case.  Without this requirement, a no-harm analysis will only assess the reliability impact on Tranche 2.1, not whether specific projects in Tranche 2.1 should be built in the first place.

Additionally, it is telling that MISO proposes to include the forthcoming JTIQ in the Tranche 2.1 no-harm analysis.  Invenergy agrees the proposed JTIQ projects should be in a no-harm analysis because JTIQ is merely at the proposal stage.  In contrast, GBX has permits in all four states; acquired over 96% of the necessary HVDC main line right-of-way in Kansas and Missouri; and obtained all required long-term interconnection agreements with MISO (TCA), SPP and AECI among other development milestones.

Invenergy thanks MISO staff and the leadership for their time and consideration and we look forward to working cooperatively in future LRTP planning.

[1]  See Members Call for More Tx Expansion Following MISO’s $20B LRTP, RTO Insider (Mar. 21, 2024) (available at https://www.rtoinsider.com/74431-members-call-more-tx-expansion-miso-lrtp-blueprint/) (explaining that “MISO does its very best to ensure that it has a very open and transparent process . . . encouraging stakeholders to participate in MISO’s public planning meetings and voice concerns”) (internal quotations omitted).

[2]  LRTP Tranche 2 FAQs at 14-15 (available at https://cdn.misoenergy.org/MISO%20Long-Range%20Transmission%20Planning%20LRTP%20Tranche%202%20FAQs631005.pdf). 

Introduction

1. WPPI is a member of the Municipal/Cooperative/Transmission Dependent Utility (TDU) Sector, and joins in the comments submitted by that sector.  We add further comments below.

Chapter 1

2. At p. 6/21 of Chapter 1, MISO describes the goal of transmission planning as identifying “the optimal locations for generation to minimize the total cost between generation and transmission investment.”  Ideally this would involve a careful effort to find the low point in the combined generation and transmission cost curve (i.e., the “bathtub curve”).  MISO’s LRTP Tranche 2.1 study effort fell short of this ideal by assuming generator locations at the outset and performing limited evaluation of a single alternative resource expansion for each Future considered.

Chapter 2

3. At p. 22/155 of Chapter 2, MISO says that, in the Tranche 2.1 study, it “conducted transient stability analysis ensuring the system meets necessary performance requirements in the Midwest subregion.”  Our review of the posted reliability results indicates that not all transient stability issues were fully resolved with the Tranche 2.1 projects.  This is not to deny that those projects provide very significantly improved stability performance, or to suggest that the remaining issues are necessarily difficult to address or that they would pose significant system limitations.  We simply suggest that MISO clarify in the report that its Tranche 2.1 cases continue to show inadequate transient stability performance for some events, and thus do not fully satisfy performance requirements for the dispatch scenarios in those cases. 
4. We agree with MISO that 765 kV transmission makes sense in the scenarios considered in Tranche 2.1, as it is liable to provide the most transfer capability for a given unit of cost or land area.  This is particularly true given the opportunity to connect to and expand upon the existing 765 kV network in Indiana and states to the east.  However, new 765 kV transmission will generally make sense only where it is extended as a network, with at least two paths connecting to the existing 765 kV network, rather than as radial 765 kV. 
5. We note also that MISO’s description of voltage-related transfer-capability differences, as illustrated in Figure 2.27, presents an incomplete picture.  Where new 345 kV transmission is built using a high-capacity low-impedance design (which we should strongly consider for long-distance 345 kV transmission going forward), one 765 kV circuit is more comparable to four 345 kV circuits than six.  And once operating rules that require planning for the worst transmission contingency are considered, six such 345 kV circuits are likely more comparable to two 765 kV circuits rather than one.
6. At p. 65 of Chapter 2, MISO says “MISO intentionally planned the system to increase the SIL of regional lines when practical (e.g., use of 765 kV options and high-SIL 345 kV options for very long 345 kV lines).”  We agree that high-SIL 345 kV designs merit consideration in LRTP along with higher voltages.  However, our review of the August 6 cases—apparently the most recent cases posted—shows fairly ordinary SIL characteristics for several of the longer 345 kV lines in the portfolio, including Maple River-Cuyuna, Denver-Ludington, Maywood-Belleau, Lehigh-Twinkle, Franklin North-Twinkle, S. Fond du Lac-Jefferson and Iron Range-St. Louis Co.  We would ask MISO to clarify where it incorporated high-SIL 345 kV designs in its Tranche 2.1 planning and where this is reflected in the models.  
7. At pp. 65-66 of Chapter 2, MISO suggests that, because the proposed 765 kV lines provide substantial reactive power during moderate-loading conditions, there is no need to look at other voltage support in the LRTP process.  This conclusion is not supported, however, and MISO’s own models show significant voltage issues associated with regional transfer, particularly on long 345 kV paths for contingency outage of proposed new 765 kV facilities (which would also represent future conditions with Tranche 1 facilities in place but not the 765 kV additions, which could potentially be an extended period).  Furthermore, it is far from clear that these issues can reasonably be, as MISO suggests, addressed via non-LRTP MTEP processes, given the different inputs used in those study processes.  WPPI raised this issue in its MTEP21 Addendum comments on the Tranche 1 portfolio, and MISO’s response indicated they would consider this in the next phase.  Having not focused on this in Tranche 2.1, it is increasingly important that MISO do so in the proposed Tranche 2.2 study.
8. Our view is that MISO’s proper role in long-range planning is to try to plan around projects like the merchant HVDC projects that have been proceeding through study queues for several years, rather than planning lines that would yield similar transfer capability between similar endpoints.  We appreciate MISO’s willingness to make adjustments to its Tranche 2.1 plans in Illinois and Missouri to provide improved transfer within MISO while avoiding potential duplication with such merchant projects.
9. MISO’s description of the Near-term Congestion Analysis work appears to end before any reporting of results or lessons learned in the effort.  We are aware that MISO posted a results spreadsheet to the Sharefile site on October 14, which is the due date for this feedback.  We would ask MISO to incorporate these and any other available results into the final version of the MTEP24 report, and to extend this reporting to MTEP25 to the extent further results are available after the deadline for inclusion in the MTEP24 report.

Chapter 3

10. We encourage MISO—along with involved Transmission Owners and regulators—to ensure that the Lyon County-Lakefield JTIQ project is designed with the capability to hold a second 345 kV circuit, as this would appear to make the best use of right-of-way, and we expect this capability will be particularly important to get the most out of the 765 kV Big Stone South-Lakefield 765 kV Tranche 2.1 project.
11. We understand that the several JTIQ projects would have construction responsibility split between MISO and SPP (and between their respective Transmission Owners), and that only the MISO-responsibility projects are included in MTEP24 appendix A.  Given that approval of all the JTIQ projects would be necessary to achieve the objective of the JTIQ effort, we presume that any MISO Board approval of MISO’s share of the JTIQ portfolio would be contingent upon SPP granting whatever approval is necessary for it’s share of the JTIQ portfolio.  We ask MISO to clarify whether this is correct.

1. The TDU Sector recognizes the need for substantial improvements to the MISO transmission system to accommodate the very significant changes in the resource mix that MISO is experiencing now, and that we expect to continue. It is important that MISO and stakeholders plan upgrades to cost-effectively address this need, and we support the LRTP effort to achieve this. 
2. The TDU Sector submitted MTEP Report comments on the Tranche 1 study in 2022 emphasizing that consideration of both grid-enhancing technologies and coordination with neighboring regions on potential upgrades to non-MISO facilities and rights-of-way will be important in identifying the most cost-effective upgrades.  Neither of these appears to have played a large role in the Tranche 2.1 study process.  We urge MISO to incorporate these elements into future LRTP study phases.
3. While considerable planning has occurred with LRTP Tranches 1 and 2.1, the TDU Sector sees a need for additional planning and analysis to more fully understand the impacts of the proposed 765 kV overlay and what additional transmission is required to support its reliable integration.  The Sector would have preferred a more complete portfolio was created for Tranche 2.1 and believes that additional transmission developed in a Tranche 2.2 effort is likely required to integrate MISO’s proposed 765 kV overlay as well as address other system needs.  The Sector does not believe it is appropriate or would be effective to utilize the normal MTEP process to address reliability and other system issues driven by MISO’s regional planning.
4. The TDU Sector submitted comments on the Tranche 1 study in 2022 noting the unreliability of MISO’s LRTP overall benefit calculation, given the failure to use a consistent reference case across benefit types.  This problem continues to be present in the Tranche 2.1 benefit work.  Accordingly, MISO’s benefit estimates again appear unreliable.  For example, MISO finds that more than 20 GW of additional capacity resources would be required in the subregion if the Tranche 2.1 projects were not constructed, yielding Avoided Capacity Cost benefits, but it effectively assumes these resources would never be dispatched for the purpose of reducing production costs, reducing losses, reducing CO₂ emissions or addressing reliability issues. 
5. In addition, the sector agrees with the Potomac Economics memo of July 15, 2024 (posted to the September 13 LRTP Workshop page) that valuing mitigation of reliability issues based on the value of lost load associated with constraint management by pre-contingency load shedding will tend to significantly overstate this benefit.  Accordingly, we find MISO’s Mitigation of Reliability Issues benefit estimate particularly unreliable.
6. Transmission affordability is of critical importance to the TDU Sector.  While regional transmission buildout is necessary, MISO should be clear about and mindful of the cost impacts to customers.  Information MISO has provided on indicative Schedule 26A rates is helpful and shows the Schedule 26A rate could grow from $1.77/MWh in 2025 to over $6.00/MWh in 2035 depending on both the final costs to construct projects and actual future load levels. This is a significant cost increase that end-use customers will bear.  MISO should consider working with its stakeholders to communicate this cost impact in other terms which can be more easily understood by a broader audience (e.g., average impact to a customer bill).  As noted above, the Sector supports MISO continuing with regional transmission planning but sees a need for MISO to focus more on system optimization and for planning to overall become more dynamic and able to respond to material changes to the system.  In addition, given the large amount of transmission being identified and improved, it is also important that transmission projects which are most needed are prioritized and accelerated.  Managing congestion, addressing other system issues and continuing to plan for the future are all essential, and the sector looks forward to working with MISO on the best ways to meet these needs, which sector believes will be a combination of transmission, generation and other solutions.

NextEra Energy: Comments on the Draft MTEP24 Portfolio
Submitted: October 14, 2024

NextEra Energy Resources (NextEra), on behalf of its affiliate, NextEra Energy Transmission (NEET) appreciates the opportunity to provide comments on MISO’s September 20, 2024 Draft MTEP24 Report. NextEra’s feedback is focused on two key areas of the Draft Midcontinent Transmission Expansion Plan (MTEP) 2024 Report (MTEP24) that are part of the Long Range Transmission Plan (LRTP): (1) the benefit metrics supporting the LRTP portfolio included in MTEP24, and (2) the direct assignment of the approximately 100-mile Illinois portion of LRTP Project 31: Sugar Creek – Collins 765 kV line to  a transmission owner in the PJM Interconnection, LLC footprint. While NextEra commends MISO’s efforts to develop its forward-thinking benefits metrics for this landmark transmission portfolio and broadly supports its approval by the MISO Board of Directors, NextEra expresses concerns over the assignment of a significant portion of LRTP Project 31 to a PJM Transmission Owner and urges MISO Staff and the MISO Board of Directors to reconsider the direct assignment of that project to a non-MISO member when costs for the project will be borne by ratepayers in MISO’s footprint.

MISO’s MTEP24 Benefit Metrics Appropriately Capture the Portfolio’s Projected Benefits

NextEra recognizes the critical importance of MISO's annual Transmission Expansion Plan processes and this year’s plan, which includes projects resulting from LRTP Tranche 2.1 work, is even more critical. MISO’s development and application of key benefit metrics for LRTP Tranche 2.1 is forward-thinking and leans into the foundation MISO has built over the last 20 years, as well as FERC’s recent Order 1920 directives.[1] These benefit metrics appropriately identify that the value LRTP Tranche 2.1 projects will deliver far exceeds the cost of the investment, with a benefit to cost ratio range between 1.8 to 3.5. NextEra supports the full range of benefit metrics developed and applied in MTEP24 and provides specific support for the use of reliability metrics and the avoided investment metrics.

Reliability Metrics Appropriately Capture Risks and Mitigation of Investments

MISO uses two metrics to appropriately capture the reliability benefits brought by the MTEP24 portfolio: Mitigation of Reliability Issues and Reduced Risks from Extreme Weather Impacts. Combined, these two metrics project benefits in the range of $15 to $44 billion.[2] The mitigation of reliability issues benefit metric identifies the value that results from avoiding potential unserved load due to thermal/voltage/stability issues on the system. MISO has developed a methodology for quantifying the remediation provided by LRTP Tranche 2.1 projects, largely based on deterministic analysis to assess the need for transmission reinforcements and evaluation of optimal regional transmission solutions. Ultimately, this approach identifies the difference in load curtailment determined with and without the LRTP Tranche 2.1 projects, and that delta is the resulting reliability benefit provided by the projects. MISO has thoroughly explained its key inputs, each step of its analysis, and model assumptions, including generation and load redispatch rules or limits.[3]

NextEra strongly supports the inclusion of Reliability metrics and the methodology developed by MISO to calculate these metrics.  These metrics are essential for accurately capturing the critical reliability benefits provided by transmission, especially given the increasing strain on the electric grid from extreme weather events.

Avoided Investment Metrics

MISO has identified three metrics that it categorizes as “Avoided Investment”: Avoided Capacity Cost (ACC), Capacity Savings from Reduced Losses, and Avoided Transmission Investment. Of these, the most impactful metric is the ACC, with a calculated benefit of $16.3 billion. This metric reflects the capital cost savings from the increase in transmission capability provided by the LRTP Tranche 2.1 projects, enabling access to resources across the broader MISO footprint. This benefit measures the change in loss of load expectation (LOLE) to determine the adjustment needed to the MISO-wide planning reserve requirement to meet the LOLE target with and without the LRTP Tranche 2.1 projects.

NextEra supports MISO’s use and application of the ACC in the assessment of benefits of LRTP Tranche 2.1. NextEra acknowledges that certain commenters, including MISO’s Independent Market Monitor (IMM) have challenged the use of ACC in development of the LRTP Tranche 2.1 Business Case. While the IMM has recommended MISO eliminate ACC benefits from the analysis, MISO has acknowledged that LRTP Tranche 2.1 can send market price signals that influence resource entry and siting. Additionally, MISO has appropriately included the ACC metric because transmission provides necessary optionality relative to the location of load. As MISO has accurately commented, due to load peaks at different locations and times across the footprint, the market sends more accurate signals to new resources with transmission modeled than without.[4] Accordingly, NextEra supports continued inclusion of the ACC metric in the LTRP Tranche 1 Business Case.

MISO Should Follow Existing Tariff Provisions for Assignment of LRTP Project 31

MISO’s draft MTEP24 Appendix A includes LRTP Project 31: Sugar Creek – Collins 765 kV line, which is subdivided into three facilities in the “Facilities” worksheet. The Sugar Creek – Collins 765 kV line is an approximately 125-mile new, greenfield transmission line project between Wisconsin and Illinois that initiates in the MISO footprint at Sugar Creek, crosses the border between Illinois and Wisconsin after approximately 25 miles, and continues for another 100 miles to the Collins substation in the PJM footprint. MISO’s draft Appendix A separately identifies the transmission line project and the substation project at the Collins substation. The Facility Description field of Appendix A for the project states, “[t]his transmission line will be assigned to a PJM Transmission Owner.”[5] No further explanation, tariff, or Business Practices Manual citation is provided for this apparent direct assignment of this line to a “PJM Transmission Owner.”

The tariff provisions in effect at the time a project is approved for inclusion in Appendix A control the selection of the developer for the project. Upgrades to existing PJM facilities, like that of the Collins substation, are directly assigned to a PJM Transmission Owner. However, for the identified greenfield transmission line, such an assignment is inappropriate under MISO’s tariff. It appears MISO is not following its tariff by introducing geographic boundaries into is analysis and no basis exists in the tariff for MISO to make such an assignment to a PJM Transmission Owner. Accordingly, MISO should follow existing tariff provisions to govern the assignment of LRTP Project 31 and MISO should not include the project in the draft MTEP24 Appendix A with the notation that it would “be assigned to a PJM transmission owner” for presentation to the MISO Board of Directors. Further, MISO should engage with stakeholders about how best to equitably assign such projects because based on MISO’s current approach, ratepayers in MISO’s footprint would bear the costs of a $521.6 million project wholly recovered by a PJM Transmission Owner. In the absence of this project being awarded through MISO’s Competitive Transmission Process, MISO customers lack protection against potential cost overruns and/or schedule delays. MISO should engage with stakeholders to explain how it will protect MISO customers if it transfers oversight and control over the development and construction of a major 765 kV greenfield transmission project to a non-MISO member who is not accountable under the MISO tariff.

As recently as LRTP Tranche 1, MISO identified a project that was split by RTO boundary lines. In that situation, MISO included the transmission line in a competitive request for proposals and assigned substation upgrades to the respective incumbent transmission owners. A similar set of facts exists here with LRTP Project 31, yet MISO has stated that in addition to the substation upgrades, the Illinois portion of the transmission line itself will be assigned to the non-MISO transmission owner, while costs will be borne by ratepayers within MISO’s footprint. The facts underlying LRTP Project 31 strongly suggest that the entire 765 kV line from Sugar Creek substation in Wisconsin and Collins substation in Illinois should be included in a single competitive Request for Proposals.

Conclusion

NextEra appreciates the opportunity to provide these comments and commends the effort and work product of MISO to develop this landmark MTEP24. While NextEra fully supports MISO's MTEP24 benefit metrics, as they reflect a robust and valuable business case for the LRTP portfolio, NextEra urges MISO to reconsider its direct assignment of the Illinois portion of LRTP Project 31 to a PJM Transmission Owner and subject that MISO-funded facility to Request for Proposals under MISO’s Competitive Transmission Process.

The NDPSC appreciates the opportunity to provide feedback on the Draft MTEP24 Report. An attachment with the NDPSC’s feedback was sent to Stakeholder Relations as an attachment.

Approval is given for the attachment to be publicly posted with all other feedback.