Interconnection Process Queue Reform BPM Evaluation and Discussion IPTF 1/14/16

Interconnection Process Queue Reform BPM Evaluation and Discussion IPTF 1/14/16

Recap of the Action Items (BPM) from 2015 Develop a study calendar for the future DPP cycles Revise Business Practice manual to align with the revised Tariff Discuss if there is a need to change the existing ERIS criteria (5%/20%) Engage the IPTF to refine reliability analysis requirements Determine the need to revise existing study modeling assumptions, including discussions related to turbine change and repower scenarios Evaluate the potential for creating standard business practices to capture varying TO local planning criteria. Develop templates for System Impact Study and Facilities Studies reports Work with the Transmission Owners to expedite all administrative steps related to Facilities Studies

Study Calendar 1. Currently under development 2. First DPP cycle under new process to begin tentatively on October 17 th, 2016 3. Application Deadline September 2 nd, 2016

Existing ERIS analysis thresholds MISO Initially proposed to reduce the 20% df threshold to a lower percentage Majority of stakeholders seemed opposed to the reduction MISO did not proceed with it during the queue reform efforts, in 2015 Unless there is significant support to reduce the 20% df threshold to a lower value, MISO will not be implementing this change in the BPM

Turbine Change Requirements: Current Practice Turbine change requests for projects already in the queue are allowed IC must submit technical analysis that demonstrates that the electrical performance of the new turbines is either similar or better than the turbine model submitted during the Interconnection Request Application Based on the submitted analysis, MISO will determine if a turbine change would constitute as a Material Modification or whether such change is permissible under the Tariff

Repower: Some questions MISO has heard from ICs How is Repower different than just changing a turbine? I am just changing everything behind the boiler, without changing the turbine/generator. Do I have to go through the Interconnection Process I want to replace a 100MW Wind plant with a 100MW Solar plant I want to replace 50MW, of a 100MW Wind plant, with a 50MW Solar plant I want to retire 500 MW of Coal plant, at Location X, with a 500 MW of Gas at Point of Interconnection X I want to retire 500 MW of Coal plant, at Location X, with a 500 MW of Gas Plant at Point of Interconnection Y. I want to retire 500 MW of Coal plant, at Location X, with a 400 MW of Gas Plant at Point of Interconnection Y.

Repower: General Observations and Comments Change resulting in a reduction in MW size, compared to existing Interconnection Rights, does not have to go through a full blown reliability analysis under the GI process MISO will only study the project for Transient Stability, Reactive Power and Short Circuit, as necessary No need to study project for Steady State thermal analysis from an Att X perspective. Any incremental MW, based on existing Interconnection Rights, must go through the full blown reliability analysis under the regular DPP Studies Existing capacity will get studied for Transient Stability and Short Circuit, as necessary Incremental capacity will get studied for Transient, Short Circuit, Steady State thermal analysis and any other reliability analysis that may need to be performed as part of the regular DPP Studies

Turbine Replacement and Repower: Questions for Stakeholders Should MISO treat Turbine replacement and Repower requests the same way as New Interconnection Request get treated under the GI process? Should Turbine replacement be studied for Steady State Thermal Analysis even if the new/revised Injection MW are lower than the existing Interconnection Rights? Should Repower requests be studied for Steady State Thermal Analysis even if the new/revised Injection MW are lower than the existing Interconnection Rights? Should MISO request M2, M3 and M4 for Turbine Change/Repower projects where there is no increase in MW compared to their existing Interconnection Rights?

MISO BPM and TO LPC alignment 1. Study Models Addition to Peak and Off Peak? 2. Study Criteria ERIS 5% and 20% and Outlet Constraints Transmission Owner Local Planning Criteria 3. Other Study Scenarios Power Transfers Contingency combinations Combination of Power Transfers, Study Models and other

MISO BPM and TO LPC alignment 1. Can MISO and Transmission Owners agree to using the same ERIS thresholds? 2. What additional scenario should MISO study, in addition to Summer Peak and Shoulder Peak that would make is consistent throughout the MISO footprint) 3. Do TOs have LPC just for Generator Interconnections that are different than what would be generally used for Reliability based Planning? 4. Is 1% Steady State Voltage Deviation criteria really required? Is there a better way to capture steady state voltage deviation pre and post contingency?

Facilities Study Coordination with Transmission Owners What do the Transmission Owners require from MISO in order to start work on Facilities Studies next day after MISO handoff? Would an Umbrella Agreement fix the sequential delay shown below? MISO issues the Purchase Order Purchase Order goes through the TO Accounting System TO Billing Code is created TO Project Manager can then start charging for the project MISO will expedite its own process and review any changes needed to the Accounting System

Current NRIS Modeling - What s the problem? 1. Disconnect between NRIS evaluation for Intermittent Resources and associated Capacity Accreditation 2. ICs developing Wind projects may be required to pay for Network Upgrades to achieve 100% NRIS; yet receive only 13% Capacity Accreditation 3. Annual MTEP Deliverability process may identify Network Upgrades that the Transmission Owners have to build for maintaining NRIS rights that can t be counted towards 100% Capacity Accreditation

Opportunity to fix the problem 1. Model NRIS levels for each unit, reflective of the class average for each fuel type, in the DPP System Impact Study Analysis 2. No need to model wind at 100% since capacity accreditation is currently set at 13% (approx) 3. Example: Model an existing 100 MW wind unit at 13 MW under the following Deliverability Study for new projects requesting NRIS MTEP Annual Deliverability Study for maintaining existing NRIS Future Market Transition Deliverability Studies 4. Model new wind projects at the class average capacity accreditation values for NRIS evaluation instead of 100% 5. Existing units with NRIS values above capacity accreditation values will be kept whole from a capacity perspective

Contact Vikram Godbole vgodbole@misoenergy.org Tim Aliff taliff@misoenergy.org Amanda Jones ajjones@misoenergy.org