LRTP: Tranche 2 Anticipated Portfolio (20240315)

The indicative map for LRTP Tranche 2 contains a significant amount of 765 kV transmission.  With the large amount of planned intermittent wind and solar resources in Future 2A, the daily generation swings in MISO will exceed 100,000 MW.  The daytime/nighttime solar swings by themselves including DERs could be on the order of 100 GW.

At low load and low generation times, the transmission system will be lightly loaded.  The high amount of capacitive charging associated with 765 kV lines will cause severe high voltage across large portions of the MISO footprint if there are not adequate facilities planned with Tranche 2 to regulate this voltage.  During other times these charging effects will be diminished by high EHV flows. Statcoms, static VAR compensators, synchronous condensers and conventional generators as well as inverter-based voltage controls will be needed to control voltage.  HVDC lines should also be considered in lieu of 765 kV for their voltage control and flow control advantages.

MISO needs to consider voltage control as an important part of managing the Tranche 2 transmission system.

LRTP: Tranche 2 Anticipated Portfolio (20240315)

In the March 15, 2024, Long Range Transmission Planning (LRTP) Workshop, MISO shared the Tranche 2 anticipated portfolio and has requested feedback.

https://cdn.misoenergy.org/20240315%20LRTP%20Workshop%20Item%2002%20Tranche%202%20Anticipated%20Portfolio632013.pdf

Invenergy appreciates the opportunity to provide comments here, as we have done throughout the LRPT effort whether directly, through industry trade group comments or collaborative discussions during stakeholder planning forums and/or workshops.

1. MISO’s exclusion of advanced-stage merchant transmission in base models results in duplicative, unnecessary or overly expensive project portfolios and threatens the development of critically needed interregional lines.
2. MISO must optimize its transmission planning now to consider advanced-stage merchant transmission in base scenarios or it will rob the region of competition, access to geographically diverse resources and potentially important ties to adjacent RTOs.
3. MISO must account for GBX energy flows and the millions of dollars in network upgrades that GBX will fund in its base models to understand how it would reshape the portfolio prior to bringing it to the Board for approval.

There is no doubt that transmission expansion plans are needed to address the challenges outlined in MISO’s Reliability Imperative, but there is no justification in the MISO Tariff or otherwise for an inefficient planning process that disregards privately funded infrastructure development happening in MISO’s own footprint. By ignoring the parallel efforts of merchant transmission developers in its LRTP, MISO has demonstrated an ongoing failure in planning resulting in over a billion dollars in unnecessary costs from three projects in Tranche 1 alone and unjust and unreasonable transmission rates for MISO ratepayers.

Continuing to ignore the impact of advanced-stage merchant transmission generally, and the Grain Belt Express LLC (“GBX”) project specifically, directly impacts whether individual projects in the Tranche 1 and now Tranche 2 LRTP portfolios meet the required cost/benefit test outlined in the MISO Tariff. This is shown by an analysis recently filed by Invenergy Transmission LLC (“Invenergy”) in FERC Docket No. EL22-83 and further discussed below. MISO’s exclusion of advanced-stage merchant transmission results in duplicative, unnecessary or overly expensive project portfolios and threatens the development of critically needed interregional lines.

Project Background & Status Update

GBX is an approximately 800-mile interregional merchant high voltage direct current (“HVDC”) transmission line that will interconnect the Southwest Power Pool, Inc., MISO, Associated Electric Cooperative, Inc. and PJM Interconnection, L.L.C. power regions. The GBX Line is designed to carry approximately 5,000 megawatts of electric power and will tap into one of the country’s strongest renewable energy resource areas that has excess wind and solar generation. It will deliver low-cost energy to load centers in the Midwest and adjacent power markets. GBX will inject 6.3 terawatt hours of energy into MISO on an annual basis. Through its HVDC technology, GBX will also have the ability to precisely flow energy between SPP, MISO, AECI and PJM as needed between regions based on emergency grid conditions including extreme weather events. GBX is targeting a 2025 start of construction with operations to begin 3 to 4 years later, prior to or contemporaneous with the Tranche 1 LRTP portfolio.

Since Invenergy acquired the rights to develop GBX at the end of 2018, the project advanced significantly from a development and permitting perspective. MISO management has been continually apprised of project advancement and that GBX now has:

1. obtained siting permits in all four required states (Kansas, Missouri, Illinois and Indiana);
2. secured offtake with 39 municipal utilities in Missouri;
3. acquired over 96% of the HVDC main line right-of-way for Phase 1 (Kansas to Missouri, to the MISO interconnection);
4. executed interconnection agreements with MISO, SPP and AECI;
5. provided tens of millions of dollars in security deposits to Ameren (in MISO) and AECI to support network upgrade development and construction;
6. executed agreements with Siemens Energy, Inc. for the HVDC AC/DC converter stations that will exist in Kansas (SPP) and Missouri (MISO, AECI) and for reserved engineering and manufacturing capacity to support front-end engineering and design for the project’s HVDC converter stations and provided tens of millions of dollars in deposits to Siemens;
7. executed an agreement with Prysmian Cables & Systems USA, LLC that guarantees for the availability of the full span of overhead conductor for the GBX Line and provided millions of dollars in deposits;
8. received FAST-41 designation from the Federal Permitting Improvement Steering Council, signifying the project’s national priority importance;
9. obtained an amendment to its negotiated rate authority from the FERC, paving the way for GBX to conduct a Phase 1 open solicitation to deliver energy from generation in and around the SPP market footprint in Kansas to the Midwest;
10. officially launched the Phase 1 open solicitation; and
11. committed to fund nearly $500M of network upgrades with the vast majority of the upgrades in MISO and AECI.

Many of these indicators of project advancement were already in place when MISO proposed and then finalized LRTP Tranche 1. However, MISO refused to account for GBX energy flows or the millions of dollars in network upgrades that GBX will fund in its model to understand how it would reshape the portfolio prior to bringing it to the Board for approval.

Tranche 1:

This was especially troubling given the Northern Missouri Corridor Tranche 1 projects that will inject energy into the same part of MISO’s system as GBX. As a result, Invenergy has made the following submissions at FERC that underline the errors and harm that occur because MISO has not accounted for advanced-staged merchant transmission in its transmission planning process:

• On August 8, 2022, Invenergy filed a Complaint with FERC against MISO arguing that MISO’s current MTEP and LRTP processes are not just and reasonable and are unduly discriminatory with regard to the treatment of merchant transmission projects and MISO is not applying its Tariff properly.
• On April 3, 2023, Invenergy submitted supplemental information in the Complaint proceeding that used MISO’s models and showed the impact to LRTP Tranche 1 when GBX’s 6.3 terawatt hours of annual energy and network upgrades are accounted for, namely:

1. GBX provides $1.92B of incremental Adjusted Production Cost (APC) savings;
2. GBX mitigates an additional 77 overloads in MISO’s year 10 reliability study and another 50 in the year 20 reliability study, across all seasonal scenarios; and
3. APC savings attributable to Tranche 1 projects are shifted and change across almost all MISO local resource zones (LRZs). This is a significant, direct impact to the economic and reliability results that MISO management presented to the Board to secure approval for the LRTP Tranche 1 projects and indicative of the impact GBX will also have on Tranche 2. Despite this supplemental information, MISO management did not update its Tranche 1 analysis or include energy flows GBX in model for the LRTP 2 assessment.

• Earlier this month, Invenergy filed additional information in the FERC Complaint docket that further quantifies how impactful merchant transmission is to the LRTP modeling assumptions and results. Again, using MISO’s own models, Invenergy’s consultant examined whether three specific Tranche 1 projects in the Northern Missouri Corridor (Projects 9, 10 and 11) are cost justified when GBX is added to the analysis. Projects 9, 10 and 11 are projected to cost ratepayers a minimum of $1.46B to construct. However, when the GBX power flow impacts are added to the analysis, Projects 9, 10 and 11 achieve only $220M in reliability value and $370M in APC savings or only $590M in benefits.

This will subject ratepayers to a loss of roughly $1B. Stated another way, ratepayers will receive at best only 40 cents on the dollar invested. As MISO is aware, MISO’s Tariff allows the approval of this type of transmission only if it achieves a benefits-to-cost ratio of at least 1.0. That will not happen with Projects 9, 10 and 11.

Tranche 2:

Despite (1) over three years of discussions with MISO and its transmission owners regarding GBX; (2) GBX continuing to build on its list of development milestones; (3) the above referenced analyses demonstrating the impact of advanced-stage merchant transmission to Tranche 1; and (4) GBX having an effective Transmission Connection Agreement (“TCA”) with MISO in hand, on March 4, 2024, MISO released its initial Tranche 2 Draft Portfolio which again does not consider the impact of advanced-stage merchant transmission and worse still proposes a new 765 kV transmission “highway” that is redundant to the far more advanced GBX Project and will interconnect to the same portion of MISO’s system.

Advanced stage interregional transmission bringing geographically diverse, high-capacity renewable energy into MISO is the exact right resource at the right time to deal with the increasing demand on the grid from load growth and increasing risk of correlated outages from extreme grid events. Like CAISO in its recently approved Subscriber Participating Transmission Owner proposal, MISO should embrace interregional merchant transmission as a key element of designing a clean, reliable, affordable electric grid rather than continuing to ignore these projects or working against them.

Accordingly, Invenergy urges the MISO to:

1. Undertake a sensitivity study to evaluate the inclusion of GBX in the Tranche 1 analysis to ensure that only cost-effective projects will move forward;
2. Include GBX in the base case of its evaluation of Tranche 2; and
3. Assess whether further updates are needed to account for other advanced-stage merchant transmission in the MISO footprint. Until then, MISO will continue to present overstated or inaccurate benefits and costs in LRTP assessments, resulting in unjust and unreasonable rates. MISO must optimize its transmission planning now to consider advanced-stage merchant transmission or it will rob the region of competition, access to geographically diverse resources and potentially important ties to adjacent RTOs.

Invenergy thanks MISO for its attention to this matter and looks forward to future collaboration.

Big Rivers physical location is in the southern portion of MISO’s central region along a north-south regional seam.  This area currently has minimal Tranche 2 project support. However, projects in this area can benefit the MISO Region, while following MISO’s objective of improving reliability and transfer capability; reducing congestion; and supporting decarbonization.  These benefits will improve the reliability and resilience of the power grid transformation in the MISO region while ensuring a more stable and consistent electrical supply. Therefore, Big Rivers encourages MISO to reconsider the following concepts as part of LRTP Tranche 2 Portfolio:

Concept 1: F. B. Culley – Reid EHV 345 kV Line

Concept 2: Joppa(McCracken Area) – Reid EHV 345 kV Line

Environmental Sector comments

 re: LRTP Tranche 2 Anticipated Portfolio 

The Environmental Sector appreciates MISO’s responsiveness to stakeholder requests to provide formal feedback in response to the LRTP Tranche 2 Anticipated Portfolio presentation given at the March 15th LRTP workshop. Stakeholder support is critical to the success of Tranche 2, and that support is contingent on a clear understanding of MISO’s process and the challenges it faces. To that end, we urge MISO to:  

1. Provide additional details on how MISO settled on the current anticipated portfolio. We understand and appreciate MISO’s constraints (regulatory burden, cost, etc.) that may necessitate a bifurcated Tranche 2, and we support a second Tranche 2 portfolio.  However, stakeholders need a better explanation as to how MISO designed the current portfolio of projects: what problems did MISO intend to solve with this portfolio and how did MISO determine which issues to resolve in Part 1 of Tranche 2 (Tranche 2.1) versus which to leave for inclusion in Part 2 of Tranche (Tranche 2.2)?

2. Provide additional information on whether co-location with existing infrastructure was considered in selecting the location of the proposed Tranche 2.1 substations?  Some MISO transmission owners have faced permitting difficulties when new regional lines are not collocated with existing infrastructure.  Could MISO please explain whether it tried to maximize the use of existing corridors when identifying the location of substations for Tranche 2.1.  Does MISO have a policy about considering the availability of existing corridors when selecting substation locations during long-range planning?  Does MISO have a policy about considering sensitive areas (such as national parks, cities, socio economically depressed areas) when selecting substation locations during long-range planning?

3. Provide an explanation on why HVDC was excluded from Tranche 2.1. Stakeholders continue to raise questions and concerns regarding the consideration of HVDC and how MISO intends to move toward developing methodologies that consider, in a fair and accurate manner, the full suite of benefits and costs that HVDC could bring to the regional system.  Stakeholder consternation would be mitigated if MISO explained the metrics and data that led it to exclude HVDC from Tranche 2.1.  MISO and others have explained the difficulty in accurately evaluating HVDC technologies in the LRTP portfolio process.  And of course, what cost allocation methodology is most appropriately applied to an HVDC project designed through the MTEP process must be addressed. The Environmental Sector intends to file an “Issue Submission” to the Planning Advisory Committee to take up these discussions and we hope that MISO finds a role for HVDC sooner rather than later.  But, in the meantime, it would be helpful to understand why MISO excluded HVDC in Tranche 2.1

4. Consider the load growth predictions for Future 3A (F3A) when Designing Tranche 2.  We share concerns raised by others that the demand projections are too low to accurately capture plausible bookends over the study period. Given the eight-to-ten year time horizon for construction, stakeholders must feel confident that the Futures used to develop Tranche 2 puts us on a path to meet system needs ten years out and beyond. At the workshop, stakeholders expressed that the load growth projections in even Future F3A are insufficient. (F2A is too low because it fails to capture the rapid integration of data centers, manufacturing, cryptocurrency, artificial intelligence, and other load additions that the MISO system is currently experiencing and expects to continue to experience.) Hence, MISO’s current approach of using F1A and F2A as the plausible bookends could be insufficient for designing a robust backbone grid that can deliver energy to these new customers.  While we recognize that MISO does not have the model built for F3A, would it be possible for MISO to conduct a sensitivity in F2A using the load growth predictions from F3A? If not feasible for Tranche 2.1, could it be done for Tranche 2.2? Or, could MISO evaluate the business case for Tranche 2.1 while anticipating higher load than is reflected in F2A? The Environmental Sector does not want to delay the adoption of Tranche 2.1 but hopes MISO can find a way to recognize the dramatic changes in load expectations.

5. Produce a timeline and sequencing for Tranches 2.2 and 3. MISO must balance the need for a Tranche 2.2 portfolio with the need to complete Tranches 3 and 4 in the next few years. We share stakeholder concerns whether MISO has the resources to complete future Tranches in a timely manner.  Considering that Tranche 2 models are already built, can MISO complete Tranche 2.2 simultaneously with Tranche 3? 

The Mississippi Public Service Commission (MPSC) has avoided commenting on the specifics of Tranche 2 because it will be built in MISO North/Central and paid for by customers in those regions.

The MPSC is, however, concerned that MISO’s Tranche 2 decision-making process is flawed and that the flaw, if not challenged, may become a precedent or MISO’s common practice when focus shifts to planning in MISO South (e.g., Tranche 3).

Issue 1

Our principal concern is MISO’s decision to exclude the Grain Belt Express (GBX) project from the Tranche 2 base case despite all indications that the project will be constructed beginning 2025. Excluding GBX from the base case may cause Tranche 2 to be overbuilt it would address needs already provided by GBX.  Retail regulators have an obligation to protect retail customers against electricity charges by monopolies that are not in the public interest.

The MPSC is not confident that MISO’s offer to perform a “no harm” test will adequately evaluate GBX because it treats GBX differently than all other transmissions facilities that are built or will be built in the near term.  For new facilities like GBX, the bright line test as to whether a project is likely to be built should be state authorization, not whether an interconnection agreement was executed by an arbitrarily deadline.  In contrast, the JTIQ facilities have not received state authorization nor have they been approved by the MISO Board. 

Unlike MTEP, which is conducted annually, LRTP is the long view.  Whether an interconnection agreement is executed in January or June or December is irrelevant.  What is relevant is the likelihood that a project will be constructed in the near term.  If including a project, that is financed and has State authorization, in the base case has the potential to save retail customers billions of dollars by avoiding construction of redundant facilities (e.g., facilities providing the same benefits already provided), then MISO has an obligation to include it in the base case.  The interests of retail customers and their regulators greatly outweigh any inconvenience to MISO caused by having to restudy the Tranche of projects.  

And, to be clear, MISO Board authorization does not guarantee that a transmission project will be built.

The MPSC endorses Invenergy’s comments and recommends that MISO include GBX in the base case for Tranche 2.

Issue 2

Our second concern is whether the estimated $23 billion cost for Tranche 2 includes all the network upgrades likely to be required to support MISO’s proposed Tranche 2 portfolio (i.e., the 765 KV-AC line) and whether these upgrades have been identified. Without MISO including the cost of these upgrades in its analysis, the MPSC does not understand how MISO can determine whether MVP criteria for a portfolio will be met.

Issue 3

Third, the MPSC is concerned with the opaqueness of Tranche 2 Part 2 (T2P2).  MISO staff announced at the LRTP Workshop that MISO would split Tranche 2 into two parts.  MISO acknowledged that it has not begun planning T2P2, calculating the costs associated with those projects, or even identifying the purpose for them. Although MISO insists that T2P2 will stand on its own from an engineering and cost/benefit perspective, given the lack of discussion by MISO regarding network upgrades needed to support T2P1, we question whether one of the purposes for T2P2 is to include the network upgrades needed to support T2P1.  If so, then the cost benefit analysis for T2P1 will necessarily be incorrect.

Issue 4

The MPSC does not understand the motivation behind MISO’s latest proposal to break Tranche 2 into two parts. Consistent with MISO Staff Short Term Incentives (STI), does MISO Board approval of half of Tranche 2 (e.g., T2P1) satisfy the STI criteria? Is there other potential motivation for this late proposal?

Good afternoon, 

WEC Energy Group is concerned that MISO now intends to bifurcate Tranche 2 into 2 phases, with the 1st phase not addressing constraints driven by the n-1 outage of a 765 kV line nor the constraints not alleviated by the 765 kV portfolio.  MISO has conveniently defined these issues as "local" and assigned them to the 2nd phase of Tranche 2.  This is inappropriate for a number of reasons.  First, the cost/benefit analysis of Tranche 2 must include all of the facilities necessary to support the 765 kV infrastructure, including facilities needed to address constraints on the less than 765 kV system, even if those constraints and faclities are defined as "local".  Just like voltage support is considered a "local" issue, without that "local" support, the regional grid fails to provide its intended benefits.  Thermal constraints are no different and classifying a set of thermal constraints as "local" does not relieve the necessity to address those constraints as part of upgrades necessary to support the 765 kV infrastructure.

Second, it is inappropriate to ask the Board (or state regulatory authorities) to approve the 765 kV portfolio without a full understanding of the requisite underbuild, the cost of that underbuild, and the impact on the benefits analysis.  To do so will result in a balkanized outcome that fails to minimize cost and maximize benefits.

Third, the NERC transmission planning standards make no mention of parsing constraints into "regional" and "local" buckets.  The NERC planning standards require the identification and resolution of all constraints.  As mentioned previously, the regional grid can not reliably function without the support of "local" facilities.

WEC Energy Group questions the viabiltiy of the proposed September 2024 Board review and approval of Tranche 2 (whether just phase 1 or a complete tranche).  As MISO stated in the ISO/RTO Council's protest of NERC's petition for approval of the cold weather reliability standard, we "need to ‘get it right’ rather than just ‘getting it done’."

In our estimation, the following issues require resolution in a manner consistent with the NERC planning standards and good utility practice prior to submitting Tranche 2 to the Board for approval:

1. Full review and analysis of the impact of the GBX and SOO Green HVDC projects on Tranche 2
2. Full review and analysis of impact of the JTIQ portfolio on Tranche 2
3. Identification and resolution of “local” transmission constraints driven by the proposed 765 kV lines
4. Review and analysis of alternatives submitted by stakeholders
5. Interregional coordination with PJM, ComEd and AEP on the 765 kV terminations in their footprint

LRTP

            Illinois Commerce Commission (ICC) staff continues to support MISO’s Long Range Transmission Planning (LRTP) process. LRTP projects are anticipated to provide a series of crucial benefits, including improved reliability, lower electricity costs, and interconnection of more clean energy. These benefits broadly align with Illinois’ policy goals, as a result ICC staff generally supports MISO’s continued efforts to plan for future transmission needs based on predicted generation location, load changes, and federal and state public policies. ICC staff recognizes that transmission expansion will play a crucial role in maintaining reliability as extreme weather and the fleet’s transition to clean energy transform the needs of the bulk electric system. Tranche 2 will also impose large costs on Illinois ratepayers, particularly in conjunction with the already substantial costs of Tranche 1. As such, ICC staff strongly advocates that MISO be transparent about its cost-benefit metric selection and benefit calculations and ensure that its Tranche 2 modeling has cost-effectiveness in mind while avoiding redundant projects.

ICC staff also agrees with MISO’s plans to model Grain Belt Express in a forthcoming sensitivity analysis. ICC Staff supports the consideration and evaluation of alternative technologies in the development of the MTEP. HVDC technology has potential to efficiently move large amounts of energy over long distances with minimal line loss and provide additional ancillary services such as black start. Moreover, as a merchant project that is not seeking regional cost allocation, GBX has the potential of obviate a significant portion of the Tranche 2 projects and costs. The ICC looks forward to the results of MISO’s sensitivity analysis.

The Modeling of Merchant and Interregional Transmission Projects

The issues surrounding GBX and MISO’s modeling criteria of Tranche 2 have raised concerns regarding MISO’s process for modeling proposed merchant transmission projects within the MISO footprint. Merchant transmission has the potential to act as a counterbalance to incumbent transmission developers by providing alternative projects that potentially can provide comparable benefits at a reduced cost to ratepayers. Greater transparency is needed in how MISO accounts for merchant transmission in its modelling to maximize its potential benefits to MISO’s footprint. Moving forward, MISO should consider reviewing its current processes and/or developing clear, standardized processes for including merchant transmission in its transmission plan modeling.  MISO should develop explicit, but flexible, criteria for acting on the results of those sensitivities.

Moreover, ICC staff would like to see the results of a sensitivity analysis modeling the planned JTIQ projects. The greater transparency that ICC staff is requesting for modeling merchant transmission should also be extended to interregional projects that MISO has planned with other RTOs. Modeling JTIQ ensures that proposed projects within Tranche 2 do not lead to costly, redundant lines or overbuild of transmission projects. Establishing a clear framework for modeling JTIQ could also serve as a helpful precedent for future interregional projects.

Tranche 2 Development Process

ICC staff encourages MISO to continue educating and informing stakeholders on its Tranche 2 process. Tranche 2 offers a wide range of estimated benefits, but also comes with significant estimated costs. ICC staff understands that MISO has constraints but providing information on alternative Tranche 2 plans that were passed on after consideration, and MISO’s rationale for not including those alternative scenarios in the current Tranche 2 base case, would be helpful to Staff to have better insight into MISO’s development process of the Tranche 2 projects. MISO’s transparency reassures state regulators that the most cost-effective and necessary solutions are being implemented. 

Comments Regarding Long Range Transmission Plan (LRTP): Tranche 2 Anticipated Portfolio (20240315)

Submitted by

Association of Businesses Advocating Tariff Equity (ABATE) Coalition of MISO Transmission Customers (CMTC)

Illinois Industrial Energy Consumers (IIEC)

Midwest Industrial Customers (MIC)

Midwest Large Energy Consumers (MLEC)

NIPSCO Large Customer Group (NLCG) [1]

1. Introduction

ABATE, CMTC, IIEC, MIC, MLEC and NLCG appreciate the opportunity to respond to MISO’s request for feedback regarding the anticipated Tranche 2 portfolio of projects presented at the Long Range Transmission Plan (LRTP) workshop on March 15, 2024.[2] At this workshop, MISO provided an initial draft Tranche 2 portfolio of projects to be located in the Midwest Subregion as part of its LRTP initiative.  The Midwest Subregion is comprised of MISO’s North and Central regions respectively. MISO expects to submit a final Tranche 2 portfolio of projects to the MISO Board of Directors in September 2024. The current draft portfolio of projects is estimated to cost between $17 billion and $23 billion. MISO indicated that the proposed portfolio does not address all Midwest Subregional issues that were identified in the modeling and analytical process. MISO suggested that an additional tranche or portfolio of LRTP projects for the Midwest Subregion would be needed to deal with the unresolved regional issues. MISO did not specify a timetable for developing this additional tranche.

MISO’s current capital cost investment range of $17-$23 billion for the Tranche 2 portfolio of projects suggests that this portfolio could cost more than twice the $10.3 billion estimate projected for Tranche 1. If approved, the revenue requirements associated with this expensive build-out will be borne by customers throughout the Midwest sub-region.  We are highly concerned about the cost impacts associated with this investment – along with Tranche 1 investment. If MISO’s final Tranche 2 portfolio costs are consistent with projections, customers in the north and central portions of the MISO footprint would be responsible for up to $33.3 billion on a cumulative basis. We strongly recommend to MISO not to lose sight of the cost and affordability impacts as it finalizes the Tranche 2 portfolio of projects. Further, given that a long-term planning horizon is prone to speculation given high levels of uncertainty when hypothesizing about scenarios 15-20 years into the future, it is imperative that MISO take steps to ensure the robustness of its assumptions and demonstrate that it has only included the projects that are truly needed.  We strongly encourage MISO to promote rate stability and predictability for customers.

Our recommendations described in detail below are as follows:

1. Additional Midwest Subregion LRTP transmission beyond the Tranche 2 projects subject to MISO Board approval in September 2024 should not occur until after Tranches 3 and 4 are addressed.
2. MISO needs to strongly consider the affordability impacts of its projected investment.
3. Future 2A Base Case must represent a complete configuration of planned investment approved by the MISO Board and material interregional projects to optimize transmission planning and provide the most cost efficient solution for transmission expansion.
4. We support MISO’s proposal to test the Tranche 2 proposed portfolio against a low-end bookend.

While our comments below are focused on the long term planning related issues, it is important to also continue the focus on planning to fulfill near term needs related to system resiliency, reliability and connecting new generation resources to load centers. As MISO makes efforts to address challenges associated with the interconnection queues, we also encourage MISO to strive for increasing efficiency and interactions with utilities in the annual MISO Transmission Expansion Plan (MTEP) related process with the goal of incorporating new load interconnections in the regular MTEP process to lessen the need for expedited project reviews.

1. Background

MISO utilized Future 2A related generation expansion results to determine its Tranche 2 initial draft portfolio.  Future 2A incorporated 100% achievement of updated utility resource plans and announced state and utility goals within their respective timelines, and a resulting 96% carbon emission reduction across the MISO footprint from a 2005 baseline. Future 2A introduces an increase in electrification, driving an approximate 0.8% annual energy growth rate.  This Future includes 103GW of retirements and 369 GW of generation respectively. 

At the March 15, 2024, LRTP workshop, MISO discussed the chart below which shows the LRTP related seven-step process associated with LRTP aimed at producing “a robust, least-cost approach to meet the transmission needs of an evolving system.”  MISO is currently at steps 3 through 5 which will continue iteratively as MISO refines and validates through the business case analysis. The business case analysis includes demonstrating that the benefit to cost ratio must be at least 1:1 as per MISO tariff requirements. These steps will ultimately result in a recommended Tranche 2 portfolio of projects, which MISO expects to submit to the MISO Board in September 2024. The cost allocation for these projects utilizes the Multi Value Project (MVP) tariff requirement of recovering costs on a postage-stamp energy basis from transmission customers that withdraw energy in the Midwest sub-region.

MISO’s initial draft Tranche 2 portfolio of projects presented at the March 15^th Workshop is provided below.  As can be observed, 765KV lines have been included in the initial draft portfolio.  MISO indicated that the Tranche 2 portfolio focuses on creating a 765 kV transmission ‘highway’ within the MISO region to “maximize value based on land use, line distances, transfer levels and costs.”  MISO considered but did not choose to include any proposed HVDC transmission facilities in its anticipated Tranche 2 based on applying a minimum distance threshold where overhead HVDC transmission facilities are typically more cost effective than overhead AC transmission facilities.

1. Detailed Comments

1. Additional Midwest Subregion LRTP transmission beyond the Tranche 2 projects subject to MISO Board approval in September 2024 should not occur until after Tranches 3 and 4 are addressed. We strongly oppose any proposed procedural changes to consider two tranches or sub-tranches within the Tranche 2 Portfolio effort. MISO has been clear about its four tranche LRTP approach since 2021 and described in testimony submitted to FERC requesting MVP cost allocation by Subregion in February 2022. [3]  Specifically, Mr. Aubrey Johnson testified in part that:

The immediate LRTP tranches will be structured as follows: Tranche 1 will contain only projects to be located in the Midwest Subregion (est. 2022); Tranche 2 will contain only additional projects to be located in the Midwest Subregion (est. 2022/2023); Tranche 3 will contain only projects to be located in the South Subregion (est. 2023/2024); and Tranche 4 will contain projects addressing the subregional constraint issue (est. 2023/2024).

Aside from the fact that MISO has not discussed implementing beyond two tranches (or sub tranches within a tranche for that matter) for the Midwest Subregion, Mr. Johnson’s testimony also highlights the fact that LRTP Tranche 3 and 4 efforts that focus on MISO South and MISO North-South integration are severely lagging behind.  MISO initiated a four tranche approach to manage the related workload and complexity associated with the LRTP initiative for its entire footprint. The goal should not be to continue to resolve all regional issues MISO is anticipating by utilizing a Future that may never materialize. Rather, it is imperative for MISO to demonstrate that its proposed portfolio is least regrets and cost effective through robustness testing, which includes sensitivity cases and testing against the low-end bookend Future (Future 1A).  MISO needs to balance its LRTP effort across its entire footprint and begin focusing on MISO South related issues after its initial Tranche 2 draft portfolio is finalized and submitted to MISO’s Board in September 2024.

Thus, we recommend that additional Midwest Subregion LRTP transmission contemplated beyond the Tranche 2 portfolio of projects not be considered until after Tranches 3 and 4 are addressed.  After the Tranche 3 and 4 initiatives are completed, to the extent that MISO continues further analysis and consideration of additional projects in MISO North/Central, we expect MISO to update all its assumptions related to the Futures including but not limited to state policies, generation siting, generation retirements, fuel assumptions and load growth assumptions respectively.

2. MISO needs to strongly consider the affordability impacts of its projected investment. Current projections indicate that customers in the Midwest Subregion will need to pay for over $30 billion in investment related to LRTP Tranches 1 and 2. We are very concerned about the cost impacts associated with this unprecedented level of investment. MISO needs to analyze the cost impacts of these investments on end-use customers. MISO should also strongly consider and seek to maintain rate affordability, rate stability, and predictability for customers as it finalizes the portfolio associated with the Tranche 2 effort. Furthermore, it is important to recognize that, even when a transmission investment is projected to provide net benefit for transmission customers, such investments lock transmission customers into incurring a cost whether or not the projected benefit from incurring that cost actually materializes.    

3. Future 2A Base Case must represent a complete configuration of planned investment approved by the MISO Board and material interregional projects to optimize transmission planning and to provide the most cost efficient solution for transmission expansion. The Future 2A base case is an important reference point because it sets the foundation to (a) develop the Tranche 2 transmission portfolio of projects and (b) conduct cost/benefit analysis. Consequently, it is important that the Future 2a base case provide as complete a configuration of planned projects as possible. Failure to include a complete configuration and optimize transmission planning creates a higher level of risk of including duplicative facilities that are not necessary, which will ultimately call into question the “least regrets” justification of the portfolio.[4]

In particular, while MISO incorporated the Tranche 1 portfolio of projects and Board approved projects in MTEP’22 (Appendix A), it has failed to include certain important and relevant transmission projects in the Future 2A base case. Specifically, the following transmission projects should be included in the Future 2A base case to ensure that any of the resulting Tranche 2 portfolio of projects are not duplicative or are addressing a need that is already being resolved through other planned investment:

2023. The MTEP 2023 Appendix A projects since they were approved by the MISO Board in December 2023.
2024. The Grain Belt Express (GBX), which is an advanced stage interregional transmission line interconnecting to MISO’s system and has accomplished many significant milestones including but not limited to: obtaining siting permits in all four required states (Kansas, Missouri, Illinois and Indiana), securing offtake with 39 municipal utilities in Missouri and executing interconnection agreements with MISO.[5]
2025. The Joint Targeted Interconnection Queue (JTIQ) projects resulting from the MISO/SPP coordinated effort and which will receive DOE funding.

MISO has indicated that it plans to conduct a no-harms test with regards to GBX and JTIQ and accordingly adjust its Tranche 2 portfolio if modeling shows some elements of Tranche 2 are no longer providing a sufficient net benefit. However, this approach creates inefficiencies and unnecessary complexity. Proper cost-benefit analysis and efficient transmission expansion in the MISO region at just and reasonable rates requires that the above mentioned projects be included in the Future 2A base case.

MISO needs to conclusively demonstrate that its final Tranche 2 portfolio of projects includes only necessary projects or a “least regrets solution” to meeting long term needs. Consequently, there is a strong and valid justification to include the above mentioned planned investment in the Future 2A base case in evaluating the Tranche 2 portfolio.  Therefore, we recommend that MTEP 2023, GBX and JTIQ projects be included in the base case modeling for Tranche 2.

4. We support MISO’s proposal to test the Tranche 2 proposed portfolio against a low-end bookend. At the Systems Planning Committee on March 19, 2024, MISO’s presentation included multiple screenings to confirm Future 2A and 1A as appropriate bookends.[6] The chart below shows the differences between Future 1A and 2A assumptions with regards to additions, retirements, net peak load and carbon emission reductions respectively. We support MISO’s view that Future 1A will provide a low-end bookend as part of robustness testing, with sufficient distinction from Future 2A.

In order to validate the “least regrets” nature of the Tranche 2 portfolio of projects, it is necessary that this portfolio be demonstrated to be cost effective against a low-end bookend Future compared to Future 2A.  Given the myriad of assumptions used in the modeling analysis, it makes sense to evaluate the reasonableness of the proposed portfolio against more conservative assumptions relative to Future 2A.

Many stakeholders cite the need to update and use Future 3A load growth assumptions in Future 2A, citing higher than average load growth at the present time. However, it is important to note that there are many other areas that also require updating and we cannot cherry pick and modify one assumption.  For instance, MISO would need to update the current and projected growth in distributed energy resources – customers are also motivated to install on-site generation by the same incentives from the Inflation Reduction Act that drive higher penetration of renewable generation by utilities. Further, given the accredited capacity projections for variable resources and the need for ramping capability, utilities are also starting to reshape their resource plans.  This is evidenced by the fact that at the Markets Committee to MISO’s Board of Directors on March 19, 2024, the MISO Independent Market Monitor (IMM) indicated multiple utilities have announced multi-billion dollar initiatives to build new gas fired resources as well as proposed hybrid and storage resources.   These changes are not reflected in MISO’s Futures.  Given that MISO does not intend to revisit any of the other forecast assumptions, it would not be reasonable to just update load growth.  Should MISO decide to update load growth, all other assumptions including but not limited to generation mix, changes in resource plans, distributed generation resources and energy efficiency assumptions, would also need to be updated.

Thank you for giving us the opportunity to provide feedback.  If you have any questions, please do not hesitate to contact any one of us.

Kavita Maini

End Use Sector PAC Representative

KM Energy Consulting, LLC (Consultants to MIC and MLEC)

(262) 646-3981

kmaini@wi.rr.com

Ken Stark

McNees Wallace & Nurick LLC (for CMTC)

(717) 237-5378

kstark@mcneeslaw.com

Jim Dauphinais

Brubaker & Associates, Inc.

(Consultants to ABATE, IIEC and NLCG)

(636) 898-6725

jdauphinais@consultbai.com

Ali Al-Jabir

Brubaker & Associates, Inc.

(Consultants to ABATE, IIEC and NLCG)

(361) 994-1767

aaljabir@consultbai.com

[1] ABATE, CMTC, IIEC, MIC and MLEC are all MISO members in the End Use Sector. NLCG is a non- MISO Member stakeholder whose members include large end-use customers within Indiana that are interruptible and/or have cogeneration facilities and that take service under NIPSCO Rate Schedule 831, which allows limited market purchases through Northern Indiana Public Service Company (NIPSCO).

[2]  See https://cdn.misoenergy.org/20240315%20LRTP%20Workshop%20Item%2002%20Tranche%202%20Anticipated%20Portfolio632013.pdf

[3] See MISO application submitted in docket ER22-194-000 submitted on February 4, 2022.

[4]  For instance, Invenergy’s March 8, 2024, supplemental comments filed in FERC docket EL-22-83-000 show the impact of including the Grain Belt Express HVDC line on the Tranche 1 portfolio.  The results demonstrate that MISO’s LRTP transmission planning process has overstated ratepayer benefits and some transmission projects in the Tranche 1 portfolio may not be needed.

[5] It is worth noting that unlike all transmission projects identified and implemented in the LRTP initiative, GBX investment related costs will not be subject to MVP cost sharing but rather be recovered from the offtake arrangements.

[6]  See slide 8 results of screening analysis; https://cdn.misoenergy.org/20240319%20System%20Planning%20Committee%20of%20the%20BOD%20Item%2005%20Reliability%20Imperative_LRITP632151.pdf

TO:                          MISO Stakeholder Relations

FROM:                     ITC Holdings Corp.

RE:                          Stakeholder Feedback - LRTP Tranche 2 Anticipated Portfolio

DATE:                      April 5, 2024

_____________________________________________________________________________________

ITC appreciates the opportunity to provide feedback on the LRTP Tranche 2 Initial Draft Portfolio presented at MISO’s March 15 LRTP Workshop.

ITC generally supports MISO’s efforts to advance LRTP Tranche 2, which was planned using MISO’s recently-refreshed Future 2A.  ITC similarly supports the procedural approach and timeline for Tranche 2 development that MISO outlined at the March 15 LRTP Workshop.  In particular, ITC appreciates MISO’s commitment to “continue analyzing the anticipated portfolio, including evaluating stakeholder submitted alternatives.”  

MISO’s March 15 Initial Draft Portfolio is a good start.  However, more transmission expansion is required, and particularly in the MISO West planning region, in order to plan a robust, least regrets Tranche 2 portfolio that addresses regional reliability needs and provides widely- and equitably-distributed regional benefits. 

Ameren Services Company (Ameren Missouri and Ameren Illinois), Central Minnesota Municipal Power Agency, Otter Tail Power Company, Montana Dakota Utilities, and Xcel Energy Services (Northern States Power MN and Northern States Power WI) have jointly submitted stakeholder feedback raising similar concerns, which ITC shares.  ITC respectfully urges MISO to consider and act upon those project solutions submitted through MISO’s formal transmission solutions solicitation window that would result in a more comprehensive LRTP Tranche 2 portfolio.    

Finally, ITC thanks MISO for providing increased opportunities for stakeholder engagement and feedback going forward.  ITC also commends MISO for increasing the duration of the most recent LRTP Workshop to five hours (from three) as this increase in duration allows more time for stakeholders to engage in discussion regarding LRTP Tranche 2 justification and development. 

Thank you for the opportunity to provide feedback on the March 15, 2024 Initial Draft Portfolio for LRTP Tranche 2.

Otter Tail Power Company Tranche 2 Anticipated Portfolio Feedback

April 5, 2024

Otter Tail Power Company (“Otter Tail”) appreciates the opportunity to provide feedback on the MISO Tranche 2 anticipated portfolio (“Tranche 2 Portfolio”) that was presented at the March 15, 2024, Long Range Transmission Plan Workshop.

Otter Tail appreciates the substantial effort MISO has performed on the Tranche 2 Portfolio. However, Otter Tail has concerns with the unresolved regional reliability issues that remain after the inclusion of the Tranche 2 Portfolio. Severe thermal loading and low voltage issues remain on the transmission system within eastern North Dakota and South Dakota, as well as across Minnesota. These issues are occurring not only on the lower voltage transmission system but also on the 200 kV and above transmission system. Given the distances and the voltage level these transmission issues are occurring at, Otter Tail views these as regional, not local, transmission issues due to generation siting.

Within the MISO Core Tranche 2 reliability models, wind dispatch within Local Resource Zone #1 reaches a maximum wind dispatch of only 43% of nameplate. This reduced dispatch limit can mask reliability issues within the models that could exist under real time operation as these reliability issues are expected to be even more significant with higher output or higher dispatching of generation within the northwest region, regardless of fuel type.

The Tranche 2 Portfolio, as currently proposed by MISO, falls short of accessing some of the lowest cost generation in the northwest region of MISO. Without accessing this low-cost generation and not providing sufficient transfer capability across the MISO footprint, it leaves consumer benefits unrealized.

Further, Otter Tail has concerns with MISO relying on local planning processes (i.e., MTEP) to mitigate unresolved regional reliability issues. As stated above, Otter Tail does not believe that these remaining transmission issues are local issues but rather regional issues. Therefore, these issues should be resolved through the Long Range Transmission Plan process and the cost of these projects should not solely rest on the local zone due to the regional benefits provided.

While Otter Tail understands that MISO has not yet provided its benefits analysis, looking at the map of the current Tranche 2 Portfolio, it appears it could be challenging to achieve benefits with a homogenous spread throughout the MISO footprint.

Due to the reasons noted above, Otter Tail believes that there are enhancements that could be made to improve the currently proposed Tranche 2 Portfolio. Otter Tail has and will submit projects for consideration within the Tranche 2 Portfolio during MISO’s transmission solution window. These projects help address severe reliability issues that remain in eastern North Dakota and South Dakota, as well as across Minnesota. In addition, the projects also increase the transfer capability through and out of LRZ 1 helping gain access to low-cost generation.

Otter Tail remains committed to continuing to work with MISO, our neighbors, and states to achieve a no regrets Tranche 2 portfolio.

The NDPSC believes that MISO completely ignored the transmission needs of ND and the Dakotas in general and in so doing, ignored the goals of those in the eastern footprint who would benefit from access to low-cost generation available from these wind-rich locations. The NDPSC also believes MISO should plan for Future 2A (F2A) and Tranche 2 solutions in one portfolio and evaluate and speak to alternatives in a transparent manner – both to ensure that the projects that function together work together and to fully capture the regional reliability and other upgrade costs such that the unresolved issues are not left for MTEP or Tranche 2 part 2 to fix.

When the needs of F2A are planned in pieces, the portfolio is not maximizing value. The ability to identify, assess, and weigh alternatives for F2A then becomes impossible – preventing the ability to select a cost-effective transmission solution. Tranche 2 Part 1 may not efficiently address system needs when planned in a vacuum without knowing what is optimally needed for part 2. This is suboptimal planning and leads to missing pieces of information. 

A proper assessment of the entirety of F2A needs is critical. MISO highlighted this need when it planned for no deliverability of additional wind out of Central and Western ND in its proposed set of Tranche 2 projects. The inclusion of a single 345 kV circuit on a line terminating on the border of ND creates some deliverability but does not provide sufficient deliverability for the low-cost wind in Central and Western ND. For instance, the current portfolio leaves severe unaddressed voltage and thermal issues in North Dakota that threaten the reliability in the region. These are regional issues which should be resolved in a complete Tranche 2.  

Also unknown are the benefits that the lines on the map create – both for part 1 and part 2, which will rely on half subscribed lines in the eastern MISO footprint which need to reach the low-cost wind areas to the west. Furthermore, we question the benefit-cost that ND derives from this portfolio, since the expectation is to only see costs associated with projects to the east with no projects located within ND.

Rushing piecemeal solutions in a vacuum without allowing stakeholders reasonable time to present alternative solutions is likely to result in state siting application rejections which otherwise could have been avoided if adequate time and stakeholder input was taken.

We also have concerns with how little time for solution development has been set aside and how alternatives were not presented (only one map selected and presented). MISO should keep any solution window open for an adequate period. MISO should support stakeholders in the development of alternatives and address the unresolved reliability issues. MISO has not even demonstrated whether an HVDC or a 345 kV portfolio would better address F2A needs at a lower cost and has only used the comparison that 765 kV takes up less land usage as the justification.

The lack of transmission siting in North Dakota threatens the achievement of goals to the east, since this plan provides little additional deliverability to the region. This plan also fails to address existing curtailments that will only increase with new generation and will likely cause generators to inefficiently site closer to load.

The NDPSC believes MISO should plan Tranche 2 parts 1 and 2 together to ensure we are building the most cost-effective plan that delivers the most value for the assumptions of F2A (not unknown assumptions for parts 1 and 2) and one that provides for the deliverability of Central and Western ND resources to the region.  Absent this and more stakeholder-driven alternative maps reflecting a combined transmission solution, the NDPSC is unable to properly assess:

1. What value this portfolio provides,
2. The full scope of cost to achieve Future 2A,
3. The potential curtailment to existing and proposed generation this creates,
4. The unaddressed reliability issues left for LSEs to resolve through MTEP and part 2, and
5. The inability to justify cost benefits and ultimate cost recovery.

The NDPSC also shares Montana-Dakota Utilities Company’s, Otter Tail Power Company’s and Xcel Energy’s concerns.

The OMS Transmission Work Group (TWG) provides this feedback to MISO on MISO's LRTP: Tranche 2 Anticipated Portfolio. This feedback is from an OMS work group and does not represent a position of the OMS Board of Directors.

Late-Stage / Sensitivity Analyses

The TWG is concerned that MISO’s suggested evaluation of late-stage projects (e.g., Invenergy’s Grain Belt Express, the MISO/SPP JTIQ Portfolio) may not reasonably reflect the value of those projects. MISO has not provided adequate clarity regarding the scope and import of its proposed late-stage analysis. For instance, will this evaluation be similar to a no-harm test or a more detailed sensitivity analysis? Stakeholders need certainty regarding MISO’s intended study process and how the results of those evaluations may impact MISO’s Tranche 2 anticipated portfolio. Relatedly, the TWG requests clarity on how MISO will model or study Grid United’s North Plain Connector.

Some TWG members understand why MISO did not include the Grain Belt Express project in the base case and can agree that re-running the studies under a base case scenario may be too labor intensive. To reflect the value of the Grain Belt Express project, MISO could adjust the RRF generation in the model that matches the Grain Belt Express project MISO injection and then run the models to understand impacts on the Tranche 2 anticipated projects. 

Consultation with PJM

The TWG requests that MISO provide an update on its coordination with PJM and impacted PJM TOs regarding the portions of the proposed Tranche 2 projects in the ComEd, AEP, or other service territories. We understand that MISO proposes that the costs of all Tranche 2 projects will be allocated to load in the MISO North/Central subregion based on benefits received. Nonetheless, greater clarity on the potential benefits received by PJM (or other regions) is needed.

Tranche 2 Phase 2

The TWG requests clarity on the timing and scope of a possible Tranche 2 – Phase 2 and how this initiative may delay MISO’s work regarding Tranches 3 and 4.

Clean Grid Alliance Comments on LRTP2 Portfolio
April 5, 2024

Clean Grid Alliance (CGA) appreciates the opportunity to provide feedback on the proposed LRTP Tranche 2 portfolio. We fully support and agree with planning for MISO’s future transmission needs beyond the 5 years forward of the annual MTEP process. Planning that looks 10 and 20 years into the future allows MISO to access financial and reliability benefits not otherwise available, and results in a more robust, efficient, and dependable system for decades into the future.

While we strongly support the LRTP concept and process, we have multiple concerns regarding the proposed Tranche 2 portfolio. Information is lacking on how MISO plans to proceed with this Tranche. Does MISO intend to separate Tranche 2 into 2a and 2b, or move forward with one portfolio for Tranche 2? Overall, we do not believe MISO has identified solutions in the Tranche 2 portfolio that address ALL the most urgent needs in the MISO North system. MISO has stated Tranche 2 will have a second part, but has not identified what might potentially be addressed in that part, nor why longstanding constraints and reliability issues in Zone 1 were excluded in favor of other area constraints reflected on the March 4 map of proposed transmission lines. There either needs to be clarity that ALL needs will be addressed in one portfolio in Tranche 2, or details provided on how 2a and 2b will be divided and timely moved forward. Other concerns include load growth assumed at 1% is seemingly too low in light of indicators and trends such as significant increases in expedited project reviews due to load growth. Additionally, we believe future 3A would present a more accurate and cost efficient result in the long-term, than using Future 2A.

When asked by stakeholders at the March 15 LRTP workshop about favoring 765kV over HVDC transmission solutions, MISO noted overall cost and shorter line lengths, but did not offer any genuine analysis or details for stakeholders to evaluate. We believe this is because MISO has not done its homework on HVDC.  We encourage a genuine comparison and analysis to be undertaken and transparently provided to stakeholders. Tranche 1 utilized existing right of way, but MISO’s proposed Tranche 2 will likely largely, if not completely, require new right of way. HVDC would offer the least cost right-of-way alternative due to a smaller footprint for the same capacity as AC transmission, as well as provide other reliability and controllability attributes that MISO has identified in the Systems Attribute effort as being needed. HVDC offers cost benefits over time with lower line losses and hence savings. A comparison with the costs and benefits of HVDC captured is necessary for stakeholders to review and assess if MISO is actually offering a least cost/highest value, solution. Simply stating that cost and line length as limiting factors were the reason for MISO to select AC rather than HVDC is not sufficient or robust enough for a portfolio of this magnitude. Regardless of whether AC or HVDC transmission, constructability is a key factor to consider in choosing and prioritizing transmission upgrades to include in the Tranche 2 portfolio.

CGA strongly supports additional transmission to address providing access to and deliverability of a higher level of resources to the MISO footprint from Zone 1. Not only does Zone 1 have excellent, cost-effective resources, but significant congestion that needs to be relieved. This is an example of a high priority need to be addressed now, whether MISO decides on one portfolio for Tranche 2, or if Tranche 2 is split into 2a and 2b. Again, if Tranche 2 is split into two parts, knowing how MISO decides what moves forward in each part and WHEN a 2b would move forward, will be important.

A couple options we could support specific to the generation pocket in SE North Dakota include, but are not limited to:

1. 345 kV from Big Stone South – Hazel Creek – Blue Lake

This would need the JTIQ Bison – Hankinson – Big Stone South project to maximize the value but would address a lot of limitations, both thermal and stability, getting to the Twin Cities and beyond.

2. 345 kV from Maple River – Riverton

This would connect the Fargo area into the mid-point on the LRTP 3 project and Likely also need a second 345 kV from Jamestown – Maple River

3. North Plains Connector

This 525 kV HVDC line would connect Colstrip, MT into Oliver County, ND. It is bi-directional line that would allow power to flow both west and east, allowing for greater utilization of the line.

We applaud MISO’s effort to address longstanding voltage constraints such as the MWEX (Minnesota-Wisconsin Exchange Interface) in Tranche 2. We encourage MISO to also consider additional 345 kV  transmission in support of addressing these voltage constraints to realize the maximum benefits in the near term. Additionally, we encourage MISO to look at voltage stability issues in southwest Minnesota, which currently limit generation in that area from reaching load.

In addition to focusing on resolving voltage constraints, CGA recommends that MISO address the lack of 765 kV “underbuild” infrastructure in the proposed LRTP Tranche 2 portfolio. While MISO admitted at the March 15 LRTP workshop the need for additional 345 kV projects to support the proposed 765 kV transmission highway, the proposed LRTP Tranche 2 portfolio shows few new 345 kV projects interconnected to MISO’s anticipated 765 kV network. As MISO itself acknowledges, and CGA supports, new 345 kV infrastructure, beyond what was already approved in Tranche 1, is needed and valuable for supporting local and contingency operation of the 765 kV network, while also ensuring strong connections between the 765 kV system and the underlying transmission system. It should also be noted that new generation is unlikely to interconnect at the 765 kV level, further supporting the need for additional 345 kV buildout.

A couple options we could support specific to addressing longstanding voltage constraints and supporting the proposed 765 kV for Tranche 2 includes, but are not limited to:

1. Minnesota-Wisconsin Reliability Link

This 345 kV project would create two outlets from MISO’s proposed 765 kV hub at Pleasant Valley in Minnesota (Huntley – Pleasant Valley – Genoa) and extend eastward from Genoa – Hill Valley – Kittyhawk to serve eastern Wisconsin load centers. A north-south path from Briggs Road – Genoa and Hill Valley – Cordova would deliver renewable energy into Illinois.

2. 345 kV projects at Nobles County, Minnesota

345 kV upgrades and additions centered at Nobles County Substation in southwest Minnesota would address voltage stability issues in southwest Minnesota which limit generation in that area from serving load.

To conclude, we applaud MISO’s efforts in identifying benefits from transmission expansion by incorporating multiple benefit metrics for review that new proposed backbone transmission will bring. We strongly support MISO in this undertaking, as it will lead to a more beneficial, robust, and efficient portfolio of projects. We also support MISO’s noted intention to model the Grain Belt Express HVDC line, and we encourage opportunities for further expansion of an existing HVDC corridor that will be available following Minnesota Power’s HVDC line upgrade currently in state proceedings. Existing and already advanced assets can be leveraged to support needed grid modernization and expansion, resulting in lowered risk and realization of valuable benefits of HVDC technology.

The TDU Sector offers the following comments on the Initial Portfolio presented at the March LRTP workshop and the underlying analysis:

1. While we are aware that MISO has posted spreadsheets showing results of MISO’s reliability analysis for a variety of cases, both with and without the projects in the initial portfolio, we presume that MISO is relying on only a subset of this data for the specific results MISO highlights in its presentations.  We would ask that MISO make available corresponding spreadsheets with the data underlying the specific figures included in MISO’s presentations.
2. MISO should ensure consistency in contingencies considered in its analysis and the addition of contingencies associated with the new facilities.  For example, if MISO wants to consider P2 contingencies in its analysis, then all appropriate contingencies of that type associated with the new projects should be added to the analysis. 
3. MISO equates a single 765 kV circuit to three double-circuit 345 kV lines, presumably on the basis of effective power-carrying capacity, which is a function of a line’s surge impedance loading (SIL) level.  This comparison is based on conventional 345 kV designs, rather than advanced low-impedance designs, such as AEP’s BOLD design.  High-capacity low-impedance designs have significantly higher transfer capabilities.  AEP’s BOLD line design, for example, has a significantly higher SIL than typical MISO 345 kV lines, such that two double-circuit BOLD 345 kV lines—rather than three—would be equivalent to a 765 kV circuit, even before considering critical-contingency effects.  We would ask MISO to include BOLD 345 kV in future illustrations of this issue and to consider high-SIL designs for new 345 kV LRTP lines.
4. We emphasize the need for MISO to evaluate the Initial Portfolio with respect to the issues listed below, taking the time necessary to fully evaluate these issues, and we question whether this can be done on MISO’s current schedule:
   1. Review of impacts of GBX and SOO Green lines, for which some projects in the Initial Portfolio appear potentially duplicative
   2. Review of JTIQ impacts
   3. Identification and resolution of significant “local” transmission issues driven by the proposed 765 kV lines
   4. Review of alternatives submitted by stakeholders (alternatives due April 5, 2024)
   5. Coordination with PJM and ComEd on the 765 kV terminations in their footprint

The following comments are being submitted by:

• Ameren Services Company (Ameren Missouri and Ameren Illinois)
• Central Minnesota Municipal Power Agency
• Otter Tail Power Company
• Montana Dakota Utilities
• Xcel Energy Services (Northern States Power MN and Northern States Power WI)

Collectively, our companies generally support MISO’s efforts on the Long-Range Transmission Plan (LRTP), which includes a second portfolio of regional transmission expansion in the MISO Midwest sub-region (LRTP Tranche 2). 

We are concerned that the current initial, draft proposed set of Tranche 2 transmission lines that only addresses a limited set of reliability issues, and simultaneously creates other high voltage, significant reliability issues to be addressed at a future time.   At a high level, we believe the preliminary portfolio could be improved to:

• Resolve the most significant and impactful reliability and stability issues in the MISO West region (North Dakota, South Dakota, Minnesota).
• Resolve 345 kV under-build/under-lying system issues necessary to support a 765 kV expansion across MISO Central (and West, as applicable).
• Alleviate high levels of congestion showing up both in real time and MISO’s economic models.
• Improve economic modeling assumptions around wind dispatch. For example, MISO should use realistic wind dispatch assumptions rather than turning down wind in the models to help models to solve.

While gaps exist in the initial proposal, we believe that through collaboration, MISO and stakeholders will be able to come together on a least cost, no regrets portfolio that can be broadly supported by utilities, stakeholders, and customers.  MISO’s preliminary portfolio is the first step in that direction. 

Our companies look forward to continuing to work with MISO through the stakeholder process.  In fact, individually, our companies have submitted numerous project ideas through MISO’s formal transmission solutions solicitation window.  Using the ideas put forth by MISO, combined with the ideas submitted by stakeholders, including our companies, we believe the LRTP Tranche 2 portfolio will be a great success that aligns broadly with the goals of states, utilities, and the MISO Reliability Imperative. 

To that end, our companies encourage MISO to take the time needed to fully evaluate LRTP Tranche 2 and alternative ideas.  We see great value in transmission expansion and the need for speed so we can safely, and reliability meet the needs of the future.  However, we would rather MISO spend sufficient time developing a comprehensive Tranche 2 solution set with broad support, rather than rush to meet an arbitrary deadline of Quarter 3, 2024. 

Thank you for the opportunity to provide feedback on the March 4, 2024, initial draft portfolio for LRTP Tranche 2.  We look forward to working further with MISO and stakeholders on future iterations of the Tranche 2 portfolio.