PSC: MTEP Selection of Non-Transmission Alternatives (IR092) (20210427)

The Environmental Sector appreciates the opportunity to comment on Non-Transmission Alternatives. We particularly feel it is important to highlight that stakeholders who wish to participate in the NTA process have generally just a few weeks to do so, at best (not 8 ½ months as MISO suggests) and that the ability to receive critical feedback from the TOs and MISO in regard to alternative developments is limited and in most cases non-existent. The combination of these two things creates significant barriers to participation in the NTA process. This barrier effectively prevents participation to a significant extent.

Several stakeholders have asked for TOs to be required to populate all project information by a specific deadline, and we strongly support this request. Lack of this information is one way to prevent participation in the MTEP process by non-TO stakeholders and it has been effective. In particular, only about ½ of the projects have financial estimates. It’s impossible to compare an alternative cost when you don’t know what you are comparing it with. Even more so, the data set is not complete, making it difficult to even estimate costs. The upgrade could range from some inexpensive terminal equipment to a full line upgrade 20 miles long and $40M in cost. If MISO wishes to make the NTA process viable, it will need to make and enforce a requirement that TOs provide project specifics by Sept. The timeline for stakeholders to participate in the NTA process can only start once this information is complete.

Suggestion: Clearly state in the Tariff or BPM the information regarding cost and a brief description of the upgrade must be provided in September.

The other barrier to participation is that between Sept and Jan there are no opportunities to discuss ideas and alternatives. Dialogue with MISO and/or the TO is necessary to clarify modeling, methodologies, and proposed solutions. This doesn’t exist.

Suggestion: Hold a SPM in between Sept and Jan or another type of MISO meeting where this dialogue can occur. This could be part of the additional meetings that MISO has offered between SPM 1 and 2 and between SPM 2 and 3 under IR091.  Individual potential NTA participants should also be able to submit written questions to MISO and the TOs and receive a response within a set time period. (We also urge MISO to consider other ways that they can merge the process for consideration of transmission and non-transmission alternatives.)

The final issue is that models with justification for the projects are not provided by MISO until the end of March or mid-April. This is when work can genuinely begin related to developing alternatives. The full information on the proposed projects and the justification, as vetted by MISO is needed. There have been years when MISO has not provided this information until the end of May. MISO has explained that parties interested in participating in the NTA process can use the old models, but this is generally not a practical option. Some updates like signed GIAs can be added to the model, but retirements are not transparent and significantly impact modeling by completely change power flows in some cases. Stakeholders can only genuinely participate when this information is available. Any work done with old models could become completely irrelevant when updates are made to the MTEP models.

Suggestion: Require MISO to provide the models/justification sooner or give stakeholders longer to study the information to participate. The clock genuinely starts for stakeholders seeking to participate in MTEP as NTAs when they have full information regarding the original projects. A similar analogy is when generators do pre-queue studies. They do their best using earlier study models, but the results can vary significantly once the study group starts and the official models for that study group are built.

Again, we thank MISO for the opportunity to submit these comments and look forward to working with MISO to create a viable NTA participation process.

Transmission Owner Sector Feedback on MTEP Selections of Non-Transmission Alternatives (IR092)

May 18, 2021

At the April 27, 2021 meeting of the Planning Subcommittee (PSC), MISO Introduced two topics submitted by Stakeholders for further discussion, MTEP Timing Adjustments to Incorporate Stakeholder Feedback and MTEP Selection of Non-Transmission Alternatives, on which feedback was requested from stakeholders regarding potential process changes or improvements, as well as framing the items for System Planning Committee discussion in June. 

Timing is a critical element of transmission project planning and execution, and as both of the items kicked off for discussion in the April Planning Subcommittee meeting have the potential to impact the certainty of the approval of transmission solution selected by the Transmission Owner as it was proposed, the timing and processes relating to these two items must be considered together.

In the April 27, 2021 Planning Subcommittee (PSC) meeting, in framing the discussion regarding MTEP Selections of Non-Transmission Alternatives (IR092), MISO requested Stakeholder feedback on the following questions, which the Transmission Owners’ Sector respond to below:

• What additional non-transmission alternatives should be considered beyond generator interconnection and demand response?
• At what point in the interconnection process should projects be considered that can also account for the contractual assurance that the selected solution will be implemented by the required in service dates?

What additional non-transmission alternatives should be considered beyond generator interconnection and demand response?

As the composition of generation on the grid changes, Transmission Planners will need to look to new technologies to meet the needs of the transmission system as it is evolving.  Therefore, defining potential items that may today be thought of as NTA as such might not be the best path forward in crafting the process for the consideration of these potential alternatives.

For example, less than 5 years ago storage as a transmission solution would have been exclusively defined as a generator, but as applications for this technology have advanced, FERC has accepted classification of storage assets as transmission under certain conditions.

The existing BPM definitions for generators and Demand Side Management as Non-Transmission Alternatives, should be reevaluated, for potential modification, as they were drafted some time ago.

At what point in the interconnection process should projects be considered that can also account for the contractual assurance that the selected solution will be implemented by the required in service dates?

For Generators, currently a signed GIA is required for inclusion in Transmission Reliability Planning models, and similar requirements apply to the requirement for contractual obligations to be demonstrated for Demand Side Management solutions.  As MISO noted in its presentation on this topic to the PSC, “if reliability issues are identified Transmission Owners have an obligation to appropriately mitigate identified issues. Without contractual commitments for Non-Transmission Alternatives noncompliance or original project in-service delays may be at risk.” 

While requiring an executed GIA before including a generator in a reliability study model will reduce this risk, it is not eliminated because even an executed GIA can be withdrawn before construction begins or the project may be delayed past the Commercial Operation Date agreed to in the GIA.  So, although these requirements can be re-visited, Transmission Owners will still require assurance that their compliance and load serving obligations will continue to be met.

Alliant Energy supports the feedback and concepts contained in the comments from DTE.

WPPI offers the following comments on the issue of MTEP Selection of Non-Transmission Alternatives (IR092) (20210427):

What additional non-transmission alternatives should be considered beyond generator interconnection and demand response?

• We are aware of DTE's comments pertaining to conversion of large synchronous generators to synchronous condensers, and we support consideration of the changes DTE proposes.  Beyond the case of synchronous condensers, we are not aware of non-transmission alternatives that should be considered beyond generation (including energy storage) and demand response.

At what point in the interconnection process should projects be considered that can also account for the contractual assurance that the selected solution will be implemented by the required in service dates?

• We are supportive of consideration of an alternative written understanding of intent to construct a new generation facility, one that could serve as a replacement for an executed GIA, particularly where preliminary indications are that required interconnection Network Upgrades will be modest and well defined. 
• We are aware of DTE's detailed comments suggesting alternatives to executed GIA for providing the contractual assurances required for NTAs in MISO's process.  We support consideration of the changes DTE proposes.　
• The current practical difficulties of considering new generator interconnections in MISO's planning process also points to the importance of trying to reduce DPP study timelines and of identifying system needs well ahead of the MTEP cycle in which transmission-project approval would be required, making use of MTEP Appendix B as appropriate.　
• Finally, we note that the fuel-type dispatch assumptions for interconnection study of energy storage appear to not fully account for the potential flexibility of such facilities, or for their potential to rapidly respond to sudden changes in system conditions. 　These topics merit continued consideration by MISO and stakeholders.

WEC Energy Group was given the opportunity to review the feedback submitted by DTE in response to the IR092 feedback request.  WEC Energy Group fully supports the continued development of the NTA and SCU concepts within the DTE feedback.