RECBWG: LRTP Cost Allocation Proposal (20210428)

Midcontinent Independent System Operator, Inc. (“MISO”) Stakeholder Feedback Submitted by the Certain MISO Transmission Owners (“TOs”) to the MISO Regional Expansion Criteria and Benefits Working Group regarding the Certain MISO TOs’ April 28, 2021 Cost Allocation Proposal for MISO Long-Range Transmission Plan (“LRTP”)

RECBWG: LRTP Cost Allocation Proposal (20210428)

Due: 05/12/2021

 I.                   April 28, 2021 MISO Stakeholder Feedback Request

In the April 28 meeting of the Regional Expansion Criteria and Benefits Working Group (RECBWG), a cost allocation proposal for Long Range Transmission Planning (LRTP) was shared by Certain Transmission Owners.  To help inform next steps, stakeholders were invited to send feedback on the following guiding questions by May 12: 

1. How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)
2. How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)
3. What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)
4. What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)
5. Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

II.                Identity of the Certain MISO TOs

The “Certain MISO TOs” that presented to stakeholders at the April 28, 2021 RECB stakeholder meeting are:

1. International Transmission Company, Michigan Electric Transmission Company, LLC, and ITC Midwest LLC  
2. Xcel Energy
3. Great River Energy
4. Ameren
5. Otter Tail Power Company
6. MidAmerican Energy

 In addition, the Certain MISO TOs have continued to engage in outreach to other MISO TOs and are hopeful that the constituency of this group will continue to evolve over time. 

 III.             Certain MISO TOs’ Response to MISO Stakeholder Feedback Request

Question 1:  The definition of “system-level reliability” on Slide 8 of the presentation is appropriate for the current stage of cost distribution discussions.  As MISO has informed stakeholders, the LRTP transmission projects are necessary to provide additional reliability and to provide MISO with the ability to move large amounts of power over long distances to accommodate the transformational shift in the generation resources in MISO’s footprint.  As documented in MISO’s Report on the Reliability Imperative, large amounts of baseload generation in MISO’s footprint have retired and have been (and will continue to be) replaced by intermittent generation resources such as wind and solar.  The transmission system operated by MISO is currently being asked to perform in a manner far different from the way it was originally designed to perform during previous grid conditions consisting of more predictable power flows. The stresses on the MISO transmission system are evident (as most recently evidenced by the February 2021 Arctic weather event) and will only continue to increase as the renewable generation transition in MISO’s footprint continues to accelerate through 2039, as projected in MISO’s updated planning Futures and as discussed in MISO’s Renewable Integration Impact Assessment (“RIIA”) study.  This pressing need for an expeditious solution to MISO’s Reliability Imperative, combined with the unavoidable “long-lead time” nature of the LRTP transmission solution component of the Reliability Imperative, led the Certain MISO TOs to name “urgency” as their first LRTP Cost Allocation Principle: Sees the urgency for additional transmission needed to meet current utility resource plans. 

 Question 2:  The proposed cost distribution solution for the costs associated with the system-level reliability component of LRTP projects, as discussed in the April 28, 2021 RECB stakeholder meeting at Slides 10 and 11, is appropriate.  In particular, given that the LRTP projects provide “system-level reliability” (as discussed, above) it is appropriate that the MISO Tariff distribute the costs of LRTP projects to a broad group of ratepayers within MISO on a “sub-regional postage stamp” basis that is smaller than the entire MISO footprint.  Because stakeholders appear to have already broadly rejected a Multi-Value Project (“MVP”)-style 100% footprint-wide cost distribution, a sub-regional postage stamp solution is therefore appropriate. 

 It is important to note that the LRTP initial Future 1 projects that are intended to be subject to the Certain MISO TOs’ proposed cost distribution solution primarily are based on announced utility plans, and are intended by MISO to be “foundational” transmission projects that create a working framework for MISO to leverage in Futures 2 and 3.  As a result, large areas of MISO’s footprint will benefit from the regional reliability improvements provided by LRTP Future 1, which further supports the use of a “sub-regional postage stamp” for broader system-level reliability benefits.       

Question 3:  During the April 28, 2021 presentation to RECB, the Certain MISO TOs stated that “[w]hile LRTP are reliability driven, they could provide quantifiable economic benefits” and proposed to “[d]etermine quantifiable benefits, if any;” and to “distribute costs to zones up to the total quantifiable economic benefit value” (Slide 10).  Further, the Certain MISO TOs proposed several “[p]rospective metrics for cost distribution” on Slide 11.  The three prospective economic metrics for cost distribution, as discussed on slide 11 of the April 28 presentation, are appropriate for LRTP cost distribution of any quantifiable economic benefits associated with LRTP projects.  The three economic metrics referenced on Slide 11 are widely-recognized benefit metrics that have the added benefit of drawing from MVP and MEP MISO Tariff provisions that have previously been approved by FERC. 

 Question 4:  The Minimum Project Cost ($20M) and Minimum Voltage (100kV) project criteria for LRTPs are appropriate, as proposed.  The two project characteristics were drawn directly from FERC-approved MISO Tariff MVP project characteristics.  As discussed above, LRTP projects and MVP projects share many characteristics, particularly scope and scale as well as a focus on reliability and, potentially economics.  The Certain MISO TOs’ proposed LRTP characteristics satisfy Certain MISO TO Cost Allocation Principle 2.

 The Certain MISO TOs appreciate the opportunity to provide stakeholder feedback and also look forward to reviewing feedback from other stakeholders and continuing cost distribution discussions. 

*          *          *

NIPSCO appreciates the opportunity to provide feedback. NIPSCO has the following answers to the questions.

1. System level reliability can be defined as projects that enable the transfer of energy throughout the market and between markets when it is needed the most. Power transfers could be limited by thermal or voltage reliability constraints during extreme conditions.　

2. A flow based (LODF or DFAX) cost allocation methodology performed before and after the project could be appropriate to allocate costs to each TPZ above any measurable economic benefit from MISO's Adjusted Production Cost metric. 　

3. MISO's Adjusted Production Cost metric could still be used as a basis to allocate costs of economic projects to TPZ's. NIPSCO recommends decreasing the LSE Revenue Return rate on imports from 80% to 20% within the APC calculation to reflect the fact that purchased power from external zone resources is largely unhedged or exposed to congestion costs. 　

4. NIPSCO recommends the project criteria to be greater than 100 kV and costs above $5M.　

5. It's important that different scenarios are considered where flow based benefits could be weighted averaged in case a TPZ in another future or scenario has different flow based benefits. Smaller "portfolios" could exist within LRZ's or between LRZ's. NIPSCO believes that we are not starting from scratch and should focus on completing and filling in the gaps of the original MVPs.

See PDF'd document.

End Use Sector Comments Regarding Certain Transmission Owners’ Cost Allocation Proposal Associated

with Long-Range Transmission Planning (LRTP) Projects

The End-Use Customer Sector[i] appreciates this opportunity to provide comments regarding Long Term Transmission Planning.

In the April 28 meeting of the RECB Working Group, a cost allocation proposal for LRTP was shared by Certain Transmission Owners.  Stakeholders were invited to send feedback regarding a specific set of questions. The End Use Sector’s comments below do not respond specifically to each of the questions.  Rather, our intent is provide overarching policy feedback regarding the cost allocation proposal at the present time.

At its core, we understand the cost allocation proposal of the Certain Transmission Owners for LRTP projects to be as follows:

• Distribute costs to zones up to the forecasted total quantifiable economic benefits using metrics similar to the current metrics for Market Efficiency Projects (MEPs)
• Consider any remaining project costs to be reliability-related and distribute these remaining costs on a sub-regional postage stamp basis, with the scope of the sub-regions as yet undefined.

The End Use Sector is concerned about the proposed approach for three major reasons:

First, the RECB Working Group spent approximately two years fully vetting the cost allocation of MEPs.  The outcome was a general consensus and explicit recognition to shift away from a postage stamp approach.   Instead, MISO recommended and the FERC approved a proposal to allocate 100% of MEP costs to Cost Allocation Zones (CAZs) and/or Transmission Pricing Zones (TPZs) in a manner that is consistent with the distribution of project benefits, using three objective and quantifiable benefit metrics.  Given the FERC’s recent determination that it is appropriate to eliminate the postage stamp component in the context of MEPs, an LRTP cost allocation approach that includes a postage stamp component would be inconsistent with the FERC’s recent findings and would also be inconsistent with the FERC’s policy and appellate court precedent of ensuring that the allocation of project costs should be roughly commensurate with the distribution of project benefits. 

Second, to the extent an LRTP project is being justified on the basis of reliability need, its costs should allocated to the specific MISO Transmission Pricing Zones that are causing the reliability need based on forecasted resource changes, forecasted demand changes and policy mandates within those Transmission Pricing Zones.  The costs should not be allocated on a postage stamp basis to all Transmission Pricing Zones.  Allocation on that basis would create cross subsidies between Transmission Pricing Zones as it would require customers in one Transmission Pricing Zone to pay for the cost of transmission facilities whose need is being driven by actions or decisions made in other Transmission Pricing Zones.  Consequently, such a cost allocation would be inconsistent with fundamental cost causation principles of ensuring that the allocation of project costs should be roughly commensurate with the distribution of project benefits.

Third, the proposal of the Certain Transmission Owners appears to ignore the important role pricing signals play in the generator interconnection process.  If it is more expensive to site generation in remote locations, it is important that we do not mute or distort these pricing signals by overlaying them with a socialized approach.  Generation project developers benefit from integrating their projects in the MISO footprint and should be assigned their fair share of costs. The current MISO Queue is dominated with renewable generation.  Accurate pricing signals are important in considering new transmission to accommodate this generation.  That is, if the driving force of building new transmission is to reliably integrate renewable generation, accurate pricing signals need to be provided to developers in terms of the level of investment required so that they can accordingly make their business decisions.  This approach appropriately directs the costs to entities causing the cost, will not favor one type of generation over another and is more effective compared to the proposed approach of socializing these costs.  Therefore, to the extent the reliability need for LRTP projects is driven by the need to interconnect and to integrate new generation resources, such resources should continue to pay a portion of the LRTP project costs as they would under the current MISO generation interconnection process. 

We support the application of the existing MEP provisions in the MISO Tariff for purposes of quantifying and to allocating the costs of LRTP projects that are forecasted to provide economic benefits including a requirement of 1.25 benefit-to-cost threshold.  To the extent certain upgrades are forecasted to provide economic benefits that go beyond those evaluated under MISO’s current MEP provisions, we are open to evaluating those additional economic benefits provided that any new benefit metrics that may be added to the existing MEP benefit metrics must be objective and quantifiable and must not be duplicative of the benefits that are reflected in the existing MEP metrics.  We strongly oppose the notion of assigning project costs on the basis of benefits that are subjective, non-quantifiable or are duplicative of economic benefits already accounted for in the MEP provisions.

Kavita Maini

KM Energy Consulting, LLC (Consultants to MIC)

(262) 646-3981

kmaini@wi.rr.com

Jim Dauphinais

Brubaker & Associates, Inc.

(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)

(636) 898-6725

jdauphinais@consultbai.com

Ali Al-Jabir

Brubaker & Associates, Inc.

(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)

(361) 994-1767

aaljabir@consultbai.com

Kevin Murray

Ken Stark

McNees Wallace & Nurick LLC (for CMTC)

(614) 719-2844

murraykm@mcneeslaw.com

kstark@mcneeslaw.com

Steve Dowell

Alcoa Power Generating Inc.

(812) 842-3377

Steve.Dowell@alcoa.com  

Date: May 12, 2021

Responses from the ACP and CGA to Questions Posed by the Regional Expansion Criteria and Benefits Working Group on April 28

The American Clean Power Association (ACP)[1] and the Clean Grid Alliance (CGA)[2]appreciate the opportunity to provide these responses to the questions posed by the Regional Expansion Criteria and Benefits Working Group (RECBW) regarding the cost allocation proposal put forth by Certain Transmission Owners at the RECBWG meeting on April 28.  ACP and CGA are strong supporters of the MISO Long-Range Transmission Plan (LRTP), designed to identify efficient transmission and non-transmission solutions to reliably support the portfolio shift underway across the MISO footprint.  We look forward to continued active engagement in the LRTP process, including the timely establishment of a cost allocation methodology for transmission projects developed therein. 

Questions 1- 4

Regarding questions one through four, ACP and CGA generally support the responses submitted by the Environmental Sector.

Question 5

 At the RECBWG meeting on April 28, several stakeholders expressed a concern that cost allocation for LRTP projects in MTEP21 should include a mechanism for generators to pay a portion of the costs of these lines.  Generation Interconnection (GI) customers remain open to the discussion of a generator contribution to regional transmission projects.  In fact, ACP and CGA made that position clear in our August 13, 2020 letter and attachment sent to the Organization of MISO States, MISO staff, and MISO Sector Representatives (attached hereto), wherein we stated that:

Our organizations are prepared to participate in discussions, in the MISO RECB work group or in a process the OMS may undertake, of new cost allocation approaches that fairly charge generators for the benefits they receive from regional grid expansion, and that compensate them for their financial contributions to this expansion.  We stand ready to participate in a discussion with OMS and other stakeholders and would welcome the opportunity to present to OMS at the appropriate time.

However, as also explained in the letter, any discussion of generator contribution for regional transmission projects should be married to consideration of benefits received by load from larger transmission upgrades identified and charged to GI customers as part of the Generator Interconnection process.  This comprehensive discussion regarding establishment of a fair cost allocation methodology for regional transmission projects and GI network upgrades will be complex, likely contentious and time-consuming, and likely difficult to complete in time for MTEP21. But we ultimately support this as it will be critical to facilitate approval and construction of regional transmission expansion to enable the generation shift underway and for the benefit of customers in the region.

In this regard, it is relevant to note that the Joint Transmission Interconnection Queue (JTIQ) Study, which is seeking to identify interregional transmission projects that will make possible additional generator interconnection on the MISO/SPP seam, appears focused on the development of precisely such a cost allocation methodology.  It is our understanding that this stakeholder discussion will begin in June and the goal is to produce a report in December that would address the results of the transmission planning effort as well as the cost allocation discussions. We intend to be active participants in that discussion, and the resulting JTIQ Study cost allocation approach could inform the LRTP cost allocation discussion for subsequent MTEP cycles.

Mississippi Public Service Commission and Louisiana Public Service Commission Comments regarding the Certain Transmission Owners Cost Allocation Proposal for Long Range Transmission Planning

The Mississippi Public Service Commission and the Louisiana Public Service Commission (“State Commissions”) appreciate the opportunity to comment on the Certain Transmission Owners’ (CTOs) April 28^th presentation to the Regional Expansion Criteria and Benefits Working Group (RECBWG) regarding their cost allocation proposal for Long Range Transmission Planning (LRTP).

The State Commissions support long term planning but have concerns regarding the CTO proposal. We believe the CTOs’ cost allocation proposal for LRTP (the CTO Proposal) is deficient on several grounds. First, it does not consider cost allocations to generation or for public policy decisions that are the primary drivers for the LRTP. Second, the CTO proposal represents a sea change in MISO’s cost allocation paradigm, shifting costs from renewable generators and the loads they would serve to MISO load that may not have a need for that generation, that may not have contracted for that generation, and that may not benefit from that generation.

MISO’s current approach to long-range transmission planning is severely lacking and contrary to MISO’s representations to stakeholders. In 2019, at the outset of the LRTP effort, MISO stated that the purpose of long-range transmission planning was to ensure the transmission system was optimized across the short- and long-term.[1] MISO made clear that the goal of long-range planning initiatives was “to create a future roadmap or guiding document, but not to commit to the implementation of specific solutions.”[2]     

While the State Commissions and other state regulators had concerns,[3] MISO reassured its stakeholders in late 2019 that LRTP would not lead to specific projects. Under this new LRTP rubric, MISO would identify a LRTP Roadmap that would provide better insight into long-term transmission system issues, develop an adaptive plan to address those issues, and most importantly, create an iterative planning effort whereby projects identified in the LRTP Roadmap would be evaluated further as projected reliability needs approached the near-term.

            Now, MISO is telling stakeholders that it will implement specific solutions identified in the LRTP Roadmap within the current MTEP cycle. Despite repeated calls from stakeholders, MISO has to-date refused to provide any substantive information concerning the projects contained within MISO’s LRTP Roadmap.[4]               

The State Commissions will continue to work with the CTOs, MISO, and other stakeholders to address its concerns with the CTO proposal and the LRTP Study process generally and define a LRTP framework that is transparent and principled. The CTO Proposal, which is better thought of as a strawman at this point, would be improved by: (i) eliminating postage stamp pricing unless specifically agreed to by each party that would allocated costs in that matter; (ii) recognizing that generators can benefit from LRTP construction and should be allocated a share of costs in proportion to those benefits; and (iii) capturing the impact that public policy goals are having on system reliability and assigning costs to those entities driving the system towards unreliability.

MISO’s proposed LRTP process would be improved by: (i) providing greater transparency regarding the projects included within MISO’s Indicative Roadmap and the transmission issue(s) the projects are intended to address, and (ii) developing criteria and processes for determining when projects identified through the LRTP process should be evaluated for project approval.

1. How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

System-level reliability in the context of projects identified in MISO’s LRTP process should be no different than MISO’s other transmission planning studies – i.e., determining whether the transmission plan complies with the prevailing NERC and applicable Regional Entity reliability standards. The system as designed today is reliable because it meets NERC planning and operational criteria.  As new elements are added (e.g., generation, load, distribution lines), each addition is evaluated to ensure the system continues to be reliable; otherwise, the system is incrementally modified or upgraded to continue meeting NERC criteria.  The NERC criteria is applied over the short term, incrementally, to the analysis of the impact of discrete additions on reliability. The costs for the upgrades necessary to maintain compliance with reliability standards are recovered from the market participants whose actions require the system modification.

First, MISO’s proposal presented at the April 30, 2021 LRTP Workshop – to take NERC’s short-term reliability standards and project them over the long-term study period – would be speculative at best, and contrary to how NERC requires the criteria to be applied.

1.  The NERC TPL standards require analysis against both a five-year planning horizon (the “solution horizon”) and a ten-year planning horizon (the “analysis horizon”).
2. MISO has recognized that reliability projections beyond 5 years are unreliable (not firm) because of the likelihood that future transmission projects will affect the results.[5]
3. NERC specifically does not require utilities to implement corrective action plans for projected medium-term (6 - 10 years out) reliability issues because such issues could be addressed by other transmission solutions or may change due to unforeseen load or topology changes, and/or generation additions and retirements.

Basing reliability upgrades on long-term (10+ years) forecasts of generation additions or retirements, market forces and policy trends will not lead to a reliable system and will not ensure that subsequent Baseline Reliability Projects (BRPs) will not be required.  Constructing projects to address forecasted long-term reliability issues now will be uneconomic if the generators hypothesized by MISO do not materialize, if they are sited in a different location, or if any significant changes in topography occur in the interim. In its proposal, MISO must recognize that the vast majority of MISO transmission-owning utilities are vertically integrated, their retail customers pay the costs for those generators, and that States, not MISO, have the unilateral authority to site generation.  MISO cannot direct a state to build a generation project.  Thus, the siting of RRF Units is, at best, uncertain. 

Second, reliability in the context of the LRTP should not include the identification of local reliability issues because these are best addressed by local (rather than regional) infrastructure, which also often serves local economic development objectives.  As MISO has stated previously, the LRTP focuses on the “big picture,” not smaller projects.

Third, MISO’s forecasted “system reliability” proposal would shift costs from those generator developers who are currently unknown to load that exists today.  

In sum, system-level reliability as defined by MISO at the April 30, 2020 LRTP Workshop and in its Reliability Imperative: (i) is not defined by NERC, (ii) was not intended by NERC, (iii) is purely hypothetical, (iv) is not authorized by the MISO Tariff, and (v) will shift the cost of new generator interconnection from future generation developers to today’s retail customers.[6]

2. How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

Costs for reliability projects should continue to be allocated the way they are today, either as BRPs or Reliability-Other projects. Costs to ensure that a new generator is reliably interconnected to the transmission system should continue to be assigned to the generator developer or the load that designated the new generator as a Network Resource.  If the need for reliability is a result of policy (e.g., renewable generation portfolio goals or standards) of one or more states or utilities, nothing precludes those states or utilities from agreeing to a Participant Funded project to achieve those goals; a sharing of costs between the state siting the new generators and the utilities that want that generation to serve their load.  And, where states/utilities agree, they can choose whatever cost allocation method they prefer, including a postage stamp/load ratio share.

What is not appropriate is non-voluntary postage stamp cost recovery: it is inconsistent with cost causation because it forces costs on customers that have not decided to contract with the future generators for whom the LRTP upgrades are being made. This sentiment is broadly supported by regulators as a plurality of OMS members[7] do not support involuntary regional or sub-regional postage stamp cost allocations.

3. What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

Consistent with OMS’s LRTP Cost Allocation Principles, any metric MISO uses to quantify the benefits of an LRTP must be quantifiable, capable of replication, non-duplicative, and forward-looking. 

While MISO’s Market Congestion Planning Study and the resultant MEPs are designed to improve the efficiency of the MISO energy market (e.g., eliminate uneconomic congestion, reduce MPs exposure to settlement charges), the LRTP process and the projects identified within have a broader purpose. As such, MISO should consider a broader array of benefit metrics that capture, among other things, the economic benefits that generators will receive (e.g., the ability to sell energy into the market and collect revenue from the sale of production and investment tax credits) and the contribution achieving state, local and utility goals.

The following list of potential metrics should be screened using the four criteria and discussed further:

-          APC (as applied under the MEP metrics)

-          Avoided BRPs

-          Reduced RDT Settlement Costs

-          Reduced transmission losses

-          Benefit from meeting public policy goals

-          Benefit to generators

The metrics listed above may require different methodologies, including the application of power flow analysis and production cost analysis. Others, such as avoided BRPs, may require transmission costing estimation tools and exogenous estimation of economic benefits and spillover effects of state renewable or decarbonization policies. The cost allocation granularity will be determined by the capability of the estimation models used and the tolerance to inaccuracy the parties sharing the cost of the projects agree to. 

Finally, MISO and stakeholders should not automatically apply the economic metrics used to evaluate the first Multi-Value Projects to the new LRTP process. Several of those metrics allocated benefits based on load ratio share. OMS and MISO have chosen to focus on more granular benefits and cost allocation as demonstrated in MISO’s 2020 Section 205 filing that eliminated postage stamp allocations for MEPs and provided for a more precise allocation benefits and costs. The metrics were also developed to address a particular problem in time – enabling the delivery of renewable energy required by public policy mandates, in a reliable and cost-effective manner – and as MISO has stated previously, the region faces a different set of challenges in this decade than it did in the last.

4. What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

MISO has stated previously that the LRTP process is intended to identify backbone facilities needed to move bulk power between areas of the region and has compared them to highways as opposed to local roads. It would seem then most appropriate to define LRTP projects as high voltage (230 kV+), higher cost ($50M+) projects. That said, the LRTP study process should ensure MISO considers and stakeholders are encouraged to submit lower cost, lower voltage transmission and non-transmission alternatives rather than higher costs, higher voltage transmission solutions.

5. Are there other elements not contained in the proposal by Certain TOs that should be considered? Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

The CTO proposal is deficient on several fronts. First, the CTO Proposal does not consider the impact of public policy on MISO’s long-term transmission needs.

Second, it does not contemplate cost allocations to generators despite the OMS’s position that generators can benefit from LRTP and should be assigned costs accordingly.

Third, the proposed LRTP project type would also sit outside MISO’s existing transmission project hierarchy.

Finally, and most importantly, the CTO proposal represents a sea change in MISO’s cost allocation paradigm, shifting costs from renewable generators and the loads they seek to serve to MISO load generally. The Proposal deviates from the Tariff methodology for allocating reliability costs. MISO currently allocates the costs of transmission projects driven by reliability concerns locally or to the specific entity driving the need for the project.

For example, BRPs are allocated to the zone where the project is located, as well are projects necessary to comply with a TOs’ local planning requirements. When a generator’s proposed interconnection creates a system reliability issues, the generator pays to address the issue under the current Tariff.  The CTO proposal shifts cost responsibility for future reliability upgrades from generators that would interconnect in the future to today’s customers who receive no benefit.

Instead of demonstrating that a project is cost effective (benefits exceeding costs), an LRTP project under the CTO Proposal could be cost-allocated regionally without any demonstration that the project is cost-beneficial. Assume a LRTP project costs $100M, solves a "reliability" issue in sub-region A, and generates $95M in economic benefits in CRZ 1 and 2, both of which are outside sub-region A. Currently, unless the “reliability” issue is addressing a potential NERC TPL violation within the NERC-mandated five-year solutions horizon, this project would not fit into any of the pre-set cost allocation categories (MVP, MEP, BRP, GIP) in the Tariff.[8] Under the current Tariff, if the project did address a potential NERC violation within the five-year solutions horizon, the project would be allocated wholly to the situs TPZ within sub-region A.  But, under the CTO proposal, the costs of the project would be largely borne by CRZs 1 and 2. Sub-region A would receive a small allocation ($5M).  And, the investment would be economically inefficient because the economic benefits did not exceed the costs by a sufficient margin to account for inaccuracies in assumptions, forecasts and calculations.

1. System level reliability should mean 345kV and above project which, on a longer range basis, meet a NERC TPL planning requirement and help move additional energy across the MISO footprint in regards to the proposed generation shift in the MISO generation fleet.

2. Cost allocation for the reliability component of LRTP projects should be as granular as possible and consider all cost causers and beneficiaries including cost allocation to future generators for whom the LRTP projects are being built. This is a place where examples would be very helpful to work from.

3. Economic component metrics should look at APC savings at the transmission pricing zone level. Assuming that all load in an LRZ or planning region receives the same benefit levels is arbitrary without examples to show otherwise.

4. LRTP project voltage should be 345kV and higher. Allocation to lower voltage projects should only be considered if they are directly impacted by the overlay of an higher voltage LRTP project. For LRTP modeling all future generation siting should assumed at 230kV and above facilities.

5. Cost allocation for LRTP specific reliability projects should also be given to generators. This could be accomplished by including future non-dispatchable generation in the denominator of the applicable cost allocation zone whereby load and future non-dispatchable generation in the cost allocation zone pay the same LRTP specific reliability rate. All existing generation and future dispatchable generation would not be included in the cost allocation of LRTP specific reliability projects.

RECBWG: LRTP Cost Allocation Proposal (20210428)

 Introduction

The Entergy Operating Companies (EOCs) appreciate the opportunity to provide feedback on the cost allocation proposal for Long Range Transmission Planning (LRTP) developed by the Certain Transmission Owners (CTOs). 

The EOCs support the efforts of the CTOs to help create a dialogue around potential cost allocation methodologies for LRTP projects.  The presentation and discussion at the April 28^th Regional Expansion Criteria and Benefits Working Group (RECBWG) helped to underscore the need for the region to prepare for an evolving grid and highlight the role that new transmission investment can play in addressing the challenges posed by increasing renewable penetration.  Nevertheless, the EOCs have reservations about the pace at which both the rollout of potential LRTP projects for consideration in MTEP 21 and the development of an associated LRTP cost allocation methodology are proceeding.

To date, MISO has not articulated fully the drivers for a new LRTP project type and associated cost allocation method.  We continue to believe these needs  must be defined in much greater detail in order to confirm whether there is (as some suppose) a “gap” between future system needs and the ability of the current project types and planning processes to meet those needs.  We also believe that the analysis and modelling utilized to date by MISO to justify the candidate projects have not been vetted in detail by stakeholders to the same extent as they are in typical MTEP planning cycles.  Finally, the release of only high-level information surrounding the details of the initial batch of LRTP projects coupled with the continued lack of definition around the problems they are designed to address have generally impeded stakeholder engagement on these topics.  While the EOCs understand that MISO’s goal is to seek Board approval of an initial portfolio of LRTP projects as part of MTEP21 as soon as December 2021, much work remains in a short period of time in order to obtain stakeholder consensus.

It is for these reasons that the EOCs continue to reserve judgement on the CTO proposal.  While we fully support the high-level principles articulated on slide 2 and believe it is constructive for the CTOs to engage in preliminary discussions around cost allocation while the LRTP initiative comes into focus, we  believe more information is required on the underlying projects before we can form a detailed point of view on cost assignment.  However, in the interim the EOCs offer the following feedback.

Question #1 - How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

No comment at this time. 

Question #2 - How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

We are pleased the CTO’s April 28^th RECBWG proposal support targeted cost allocation granularity where it is possible.  In general, the EOCs believe that a demonstration of receipt of quantifiable benefits by the subregion in question is a pre-requisite for cost assignment.  Cost allocation should always be defensible relative to assignments based on demonstrated benefits.  While we are open to hearing other parties’ arguments on what the appropriate level of granularity should be for LRTP cost allocation, the EOCs conceptually support limiting granularity at the individual or multiple Transmission Pricing Zone (TPZ) level. 

The EOCS strongly oppose region wide postage stamping as a cost recovery mechanism for LRTP projects.  The EOCs, however, are supportive of subregional cost allocation under the correct circumstances.  One instance where assigning costs on a subregion-wide basis could be appropriate involves LRTP projects that address the constraint between the MISO North/Central and South regions.

 Question #3 - What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

The EOCs support drawing upon the existing FERC-approved MEP cost allocation Tariff while determining how to allocate the economic component of LRTP projects.  MISO’s current suite of benefit metrics emerged after an extensive, multiyear review process and was adopted with clear stakeholder support and compelling evidence/analysis confirming that the measures are non-duplicative of other metrics and would capture meaningful and quantifiable benefits.  Due to the rigor of the prior review process, which utilized the Planning Subcommittee to evaluate the multiple potential benefits suggested by stakeholders in feedback provided to MISO, Entergy believes that the existing set of MEP benefit metrics is reasonable and appropriately captures the quantifiable benefits potentially provided by new transmission.  As part of the latest round of cost allocation reform, numerous alternative metrics were offered, evaluated by MISO, and ultimately dismissed for a variety of reasons, such as concern that they would be duplicative of existing metrics or attempt to track benefits that are illusory in nature or difficult to quantify.

Although the EOCs find the existing MEP metrics to be appropriate, we recommend the CTOs consider exploring a more granular allocation of economic benefits.  The existing APC methodology works well to calculate the production cost savings of a project, but the existing cost allocation methodology does not allow for granular allocation within a Cost Allocation Zone (CAZ).

 Question #4 - What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

 Greater specificity around the CTO’s proposed minimum voltage level of 100kv is required.  The EOCs understand that the LRTP initiative contemplates developing large scale, regional transmission projects consisting of voltage levels much higher than 100kv.  If the intent of the CTO proposal is to mirror the language found in Attachment FF of the MISO tariff (which states that an MEP involves facilities with voltages of 345 kV or higher but may include lower-voltage facilities of 100 kV or greater so long as certain conditions are met) then that intent should be stated more clearly.

 An explanation of whether the CTOs propose the use of a benefit-to-cost ratio is also necessary.  This ratio is a key indicator of the overall value of a project.  For transmission projects of the size and scope contemplated by the LRTP initiative, the EOC’s believe a benefit-to-cost ratio of at least 1.25 is appropriate. If the CTO’s intend to utilize a benefit-to-cost ratio as part of their proposal, then the proposed threshold should be identified sooner rather than later.  If the CTOs do not intend to utilize this indicator, then the CTOs should articulate its rationale.

Question #5 - Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.)

 The EOCs believe there is strong stakeholder support for including a review of the rules governing the assignment of costs associated with Network Upgrades driven by generator interconnection as part of the development of a LRTP cost allocation regime.  This issue has been lingering in the MISO stakeholder process for a considerable amount of time.  For example, in the MVP process, this issue wasn’t tackled early enough to resolve complex issues such as how payments by interconnection customers ICs would be guaranteed over time.  During our recent participation in the Organization of MISO States (OMS) Cost Allocation Principles Committee, MISO’s RECBWG and LRTP workshops, the EOCs have observed that many parties want this issue to be considered now as part of  LRTP cost allocation and resolved in time for application to MTEP21.  Although this is a complex topic that tends to generate strong and often divergent views, the EOCs think it is clear that this issue cannot be kicked down the road indefinitely and the ongoing focus on LRTP creates a window of opportunity to address this issue.  If a mechanism for generator cost assignment isn’t developed in time for MTEP21 then at a minimum the EOC’s think MISO should provide a firm commitment to resolve this issue in time for MTEP22. 

 In addition, we think the duration or applicability of the CTO proposal, if it is approved, should be further clarified.  Per the presentation, the CTO proposal is “intended to apply to Future 1 Projects until other methodologies may be adopted.”  The EOCs agree that it is reasonable to limit the application of the current CTO proposal to Future 1 Projects given the uncertainty surrounding the overall LRTP initiative.  However, the concept that the CTO proposal will apply to MTEP 21 and then to subsequent planning years until it is replaced by another TBD cost allocation scheme is too open ended.  If the advocates intend for this to be a temporary solution that only applies to Future 1 projects, then there must be firm commitment to retire it after MISO Board approval of the Future 1 projects as well as a commitment to develop a replacement regime for future projects.

Indiana Reponses -

1.            How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

System-level reliability generally means the maintenance of or increase in reliability or safety of the entire bulk electric power system while recognizing the transitioning resource mix either within the MISO footprint or, as Slide 8 implies, a sub-region within the MISO footprint. It can also refer to the ability of the bulk electric power system to withstand extreme weather events or the ability to maintain power flows to critical facilities such as hospitals and industry.

We understand the concept of system-level reliability as an extra level of reliability over and above the reliability already required by NERC standards. This enhanced standard of reliability needs to be fully developed and agreed upon by MISO stakeholders before transmission projects are planned to meet this type of reliability. MISO has not to our knowledge developed a metric or quantification of this reliability. If our understanding of system-level reliability is correct, MISO should undertake the development of such a metric. It should quantify as granularly as possible whether a transmission facility enables load to be connected at peak periods to additional lower cost generation to which the load would not otherwise have access.

Because any reliability metrics will necessarily be based on forecasts and futures, projects purporting to contribute to bulk electric system reliability should be preferred when they preserve the greatest level of optionality. In general, a number of smaller projects staggered over time provides greater optionality as compared to a single large project because smaller projects allow for course correction over time.  Projects – regardless of size -- that can be easily modified or resolve multiple issues can more readily address the fact that planning is an ever-moving target.   

2.            How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12).

               In line with the Certain Transmission Owners’ proposal, projects that address system wide reliability should be allocated on a postage stamp basis to the users of that system because reliability is in economic terms a public good that all users share. The system need not be the entire MISO system but may be a sub-region within the MISO system. Postage stamp allocation should be made to the smallest sub-region that shares the reliability benefits as modeled by MISO. This sub-region may be MISO North or MISO South, or smaller if reliability benefits are shared in a more limited area.   As long as an area shares in the reliability enhancements stemming from a project, there is no need to determine relative ratios of reliability more granular than the load ratio share in the affected areas.

3.            What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

This question, and thus our response, focuses on the allocation of costs regarding economic components of LRTP rather than any economic or other planning criteria that makes a project eligible for cost allocation. Following the hybrid approach in the Certain TO’s proposal, economic benefits of an LRTP project should be allocated in a manner similar to the allocation of benefits in MEPs, including Adjusted Production Costs and Avoided Reliability Project Savings, though preferably with a more robust set of benefit metrics allowing for heightened granularity in cost allocation.[1]  Granular economic cost allocation could offset the postage stamp allocation based on reliability as proposed in response to No. 2, above.          

In determining beneficiaries of transmission facilities, an LRTP process should consider benefits that include meeting Public Policy Requirements as contemplated in Order 1000.  Also, renewable generation may be considered a beneficiary of large-scale transmission.

4.            What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

Indiana supported a 100kV threshold for MEP projects, and supports the same threshold here, along with the Certain TOs.

In addition to the voltage threshold, Indiana supports a costs threshold that is as low as possible to include as many projects as reasonable. The Certain TO proposal of $20 million is in the correct range, though Indiana is not committed to a specific number at this time.

5.            Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

The framing of the Certain TOs proposal assumes that transmission projects are the only way to achieve the proper level of reliability, which may not be the case. Transmission issues, including the types of reliable performance challenges identified in the RIIA, can be solved not only by new transmission lines but by several types of equipment, as identified in the RIIA study.  Additionally, storage technology can help to solve these transmission issues. Transmission planning should be “best value planning” that looks to all alternatives.  Non-wire alternatives and generation locational planning can function as alternatives to transmission in varying degrees.  No matter the allocation of costs, transmission project criteria should be in place to elicit other non-transmission alternatives that could provide similar levels of reliability more efficiently.

The tradeoff between transmission connecting to remote generation resources verses local generation with less transmission is inherent in transmission planning.  Modeling in each of the Futures should enable stakeholders to make informed choices instead of assuming additional transmission resources are needed.  Projects that are other than least-cost solutions should identify the cost causers of those projects, and the additional costs should be assigned accordingly.

Overall, we view the MISO LRTP as a multi-year, iterative effort, following a logical progression from information gathering to project selection to build-out.

MISO RECBWG LRTP Cost Allocation Proposal Feedback Request

Due May 12

Minnesota Power (MP) appreciates the opportunity to provide feedback on the Long Range Transmission Planning (LRTP) Cost Allocation Proposal presented at the April 28^th Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting. MP is generally supportive of the concepts presented during the meeting and provides the following public feedback for consideration.

1.  How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

•  Pointing to the types of reliable system performance challenges identified in the Renewable Integration Impact Assessment (RIIA) to enable the reliable delivery of energy and other objectives of the MISO Futures is an appropriate way to begin to define LRTP type projects.

2.  How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

•  MISO should always strive to allocate costs to those that benefit where beneficiaries can be identified. If beneficiaries cannot be accurately identified, a sub-regional allocation may be needed to ensure the broader benefits of a LRTP line are captured.

3.  What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

• LRTP projects are reliability projects that may also provide economic benefit. The existing, FERC approved metrics in the MISO Tariff have been thought through and vetted and are the appropriate place to start but the uncertainty in the modeling in the 10-20 year timeframe might outweigh any benefits we see in performing the studies to determine economic benefits.
• Focus just on APC and allocate cost to those that benefit at the more granular Transmission Pricing Zone (TPZ) level. If a TPZ does not see a demonstrable benefit, it should not be allocated any costs.
• Due to the longer study period that LRTP is focusing on, the Avoided Reliability Project Costs metric might not be relevant. LRTP is not trying to capture near term issues that would be deferred but is focusing on the 10-20 year time frame.  
• MP is supportive of using Reduced SPP Settlement Costs as an economic metric for benefit calculations and cost distribution.

4.  What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

• Lower voltage and less regionally impactful projects do not spread benefits far. Additionally, lower voltage projects do not require the same time to develop as higher voltage projects (10+ years) and should not require an LRTP-type study to be identified and constructed within the necessary timeframe. The cost allocation discussion should not focus on lower voltage projects, but instead put efforts on transmission cost allocation for larger transmission projects and electric infrastructure that will provide more value to the region including reliability backbone type projects.

WEC Energy Group's response to the April 28 RECBWG request for feedback is contained in a separate files sent to stakeholder relations.

Michigan Public Service Commission (Michigan PSC) Feedback to the RECBWG on the 4/28/21 LRTP Cost Allocation Proposal by Certain Transmission Owners. 

1.  How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

NERC’s Adequate Level of Reliability[1] (ALR) Performance Objectives that guide its Reliability Standards development process and Bulk Electric System (BES) reliability assessments should continue to be the objective for reliability-based transmission planning. Projects identified through the LRTP should, from a reliability perspective, preserve ALR on the BES through the expected resource fleet transition in the long-term planning horizon as highlighted in the MTEP21 MISO Futures. In considering an LRTP project to mitigate a long-term system-level reliability issue for approval in an MTEP cycle, it is essential that the LRTP process be transparent regarding the specific system performance challenges that are being addressed, under what scenarios and assumptions the project is being proposed, and that it provides stakeholders a meaningful period to review planning models, provide input and develop project alternatives. This is necessary to (1) ensure that an LRTP project is the best use of ratepayer dollars to facilitate long-term system planning and needs, and (2) facilitate a transparent and consistent LRTP planning and project selection process that maintains stakeholder confidence. Having MISO articulate how these specific system-level performance challenges are to be addressed by the projects selected in a specific MTEP cycle will be an important element of this process. 

2.  How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

Relevant here, the Organization of MISO States Statement of Principles: Cost Allocation for Long Range Transmission Planning Projects (OMS Principles), principles 1, 2, 3 and 4 state:

1. The costs of new transmission projects should be allocated to cost causers and beneficiaries in a manner that is at a minimum roughly commensurate with, and preferably proportional to, the costs caused and benefits of those projects.
2. Cost allocation should be as granular and accurate as possible. Benefit-cost analysis should use metrics that are quantifiable, capable of replication, non-duplicative, and forward-looking.
3. Costs should not be allocated to parties that receive negligible or negative benefits.
4. Generators and load each can be considered cost causers, beneficiaries, or both and should be allocated costs accordingly.

The cost allocation for the system-level reliability component of an LRTP project should meet the standards set forth in these principles and be based on an analysis of reliability benefits.  MISO and the RECBWG should discuss the potential reliability benefits of LRTP projects, in detail, and what corresponding cost allocation methods might be appropriate. A postage stamp cost allocation method as proposed by the Certain TO’s, though expedient, does not conform to the OMS Principles or beneficiaries-pay principle – even for large backbone infrastructure. As a starting point for discussion, the Michigan PSC suggests that reliability-based cost allocation methods that have either been previously used by MISO and/or are currently used by other RTOs  be evaluated for how they may or may not be effective in the LRTP context, recognizing that an innovative approach may also be warranted given the long-term drivers for the LRTP projects. Such methodologies could include Line Outage Distribution Factor (LODF), which was previously used by MISO for allocating BRPs prior to the issuance for Order 1000, and Solution-based Distribution Factor (DFAX), which is currently used for determining RTO project share for cross-border BRPs with PJM and is also used by other RTOs for allocating costs associated with projects needed for reliability purposes. This should contribute to the goal of appropriately allocating the costs on a more granular basis for projects identified through the LRTP that maintain system-level reliability over the long-term planning horizon considered by LRTP.

MISO and RECBWG stakeholders should also begin exploring methods to allocate a portion of LRTP project costs to the future generators that will benefit from the LRTP projects. A transmission access charge or use charge, where participating transmission owners finance LRTP upgrades, and a portion is later repaid through charges assessed to interconnection customers who benefit from the LRTP project, may be a useful framework for discussion.

3. What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

MISO should begin with the 2020 FERC approved MEP benefit metrics and cost allocation methodologies framework to allocate the costs associated with the economic benefits of an LRTP project: APC, MISO-SPP Settlement Savings and Deferred Reliability Benefits as described in Attachment FF-7. On an ongoing basis, stakeholders should continue to evaluate through the RECBWG other economic metrics, such as decreased operating reserves, planning reserve margins or transmission line losses, etc.

4.  What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

At a minimum, LRTP projects should meet or exceed the basic cost and voltage MEP project criteria: minimum $5 Million project cost and 230 kV voltage threshold. MISO and most MISO Transmission Owners concluded that the MEP benefits of transmission operated below 230 kV are local in nature, and therefore projects below 230 kV should be ineligible for MEP cost allocation. LRTP, which focuses on larger regional infrastructure, should not have a lower voltage and cost threshold for approval than the current MEP.

5.  Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

The Michigan PSC is supportive of the Certain TO’s proposal to first determine the quantifiable economic benefits of an LRTP, and if any exist, to distribute costs to zones (CAZs) up to the total quantifiable economic benefit value, and then to distribute remaining project costs as reliability. This maintains the current project hierarchy – where reliability projects (BRPs) that also meet MEP criteria are approved and cost allocated as MEPs, preventing economic free-riders on the back of needed reliability upgrades.

The Certain TO proposal, however, proposes to distribute remaining reliability project costs on a postage stamp basis to yet-to-be defined subregions – a task that may in and of itself be prolonged and contentious. The Michigan PSC prefers that this portion of project costs be distributed to the beneficiaries of the additional reliability provided by the LRTP project, including generators, consistent with stakeholder vetted reliability metrics as discussed in our answer to Question 2.

Finally, the Certain TO proposal does not contain any proposed method to allocate a portion of LRTP project costs to future generators who will benefit from the LRTP upgrades. As noted above, the Michigan PSC suggests a possible transmission access charge or use charge to future generators who utilize the LRTP projects as a starting point for discussions. However, it is not clear that this issue needs to be addressed for any tariff revisions/ additions relating to projects to be included in MTEP 21, as such projects are unlikely to be primarily driven by resource additions and more focused on addressing bottlenecks and system limitations that currently exist and pose near-term threats to reliability. In addition, the discussions taking place as part of the SPP-MISO Joint Targeted Interconnection Queue (JTIQ) study contribute to the discussion of generator cost-share towards interconnection projects. Finding binding opportunities for stakeholders to address these issues as part of the broader LRTP cost allocation discussion involving projects to be included in MTEP 22 and beyond would be of great benefit, and the RECBWG should focus on such issues as soon as the immediate issues involving projects potentially proposed for inclusion in MTEP 21 are resolved.

General Comments

Provided below are Alliant Energy comments in response to the feedback questions from the Certain TOs April 28^th RECB Working Group presentation.  It should be recognized that the Certain TO proposal is currently missing critical details in order to fully understand and react to the proposal.  These details include specific LRTP project criteria and the role of generators in the cost allocation proposal.  Alliant stresses that changes to cost allocation should not allow for inappropriate cost shifting to occur from the generation interconnection process to other transmission customers and that any changes to cost allocation need to be supported by sufficient analysis that validates the need for the change and the proposed solution. 

1. How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

NERC planning criteria and standards should be the guidepost for defining reliability drivers with LRTP projects.  NERC planning criteria and standards should also be applied consistently across the MISO footprint to avoid differences in transmission buildout due to different interpretations of NERC planning criteria requirements by the local Transmission Owner.  In addition, any system-level reliability definitions used in transmission planning to support proposed transmission projects need to be specific and well-defined and allow other stakeholders to utilize the criteria in performing their own analysis.  If a “lower case r” reliability is to be used in planning this needs to be defined to make this concept less nebulous and so stakeholders can understand what is being referred to.

What should not be used as reliability criteria are general attributes or system issues.  For example, the fact that a proposed project may generally help address the type of low voltage issues seen in the RIIA study is not an acceptable criteria.   It is important to remember that the RIAA was not an optimized study.  While this study work is helpful in thinking about the future, the results should not be translated and used in the transmission planning process.   

1. How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

Transmission costs should be allocated as granular as possible.  Depending on the specific benefits provided by a proposed project, the appropriate granularity could be at the level of Transmission Pricing Zone, Cost Allocation Zone or broader.  Also, to the extent that reliability benefits accrue to new generators interconnecting to the transmission system, costs should be directly allocated to these generators.

1. What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

Adjusted Production Cost (APC) should be relied on to allocate the economic component of LRTP projects.  APC is the standard metric used in the industry to measure economic related impacts from a proposed transmission project.  MISO should not try and re-create the wheel but rather follow the current process regarding the use of APC.  This includes segregating and excluding the impact from RRF units for the purpose of cost allocation.  MISO should also continue to use a 1.25 benefit to cost ratio in order to use economic benefits to justify a transmission project.

1. What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

At this point, Alliant does not see the need to add any limiting criteria for LRTP projects.

1. Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

A key item missing from the proposal by the Certain TOs is how future generators benefiting from LRTP projects would share in the costs.  The overall objective of the LRTP is stated as:

Long Range Transmission Planning is necessary to ensure a reliable and efficient regional and interregional transmission system that enables the changing portfolio across the near and long term and is a part of the comprehensive Reliability Imperative initiative.

Since a primary driver of the LRTP process is to enable the changing portfolio, new generators interconnecting into the transmission system will be a key beneficiary of potential projects. The Certain TOs should explain their rationale for excluding these beneficiaries from their cost allocation proposal.

WPPI appreciates the opportunity to provide comments on the Certain Transmission Owners’ cost-allocation proposal for LRTP presented at the April RECBWG meeting. WPPI recognizes that the electric industry is in the midst of fundamental change, and that significant transmission improvements will be required to maintain electric reliability at reasonable cost with a changed resource mix.  We recognize also that changes to the planning framework and to MTEP project definitions may be necessary. We stress, however, that i) the LRTP process must focus on identifying the most cost-effective upgrades; and ii) it remains the case that determination of cost-causers and beneficiaries will play an important role in this process and that costs should be allocated to the extent possible consistent with this determination.

1. How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

• We expect that reliability analysis as conducted for LRTP will be fundamentally similar to that applied in traditional MTEP reliability planning, which is: for a given dispatch, the system is tested against defined criteria for defined plausible contingencies.

• The primary difference raised by LRTP study, and hence the difference we see between traditional notions of reliability and the concept that arises in the context of LRTP, concerns the generation dispatch in the planning cases, where LRTP will likely consider a relatively wide range of varying intermittent-resource output patterns.  In addition, rather than requiring reliability criteria to be strictly satisfied in each dispatch scenario, we believe LRTP should allow for flexibility to choose which constraints can be addressed via re-dispatch, subject to satisfying a specified aggregate criterion (e.g. for meeting public-policy goals).  In addition, and possibly more importantly, an appropriate planning process should consider different configurations of types and locations of generation and energy storage in order to identify resource sets yielding near-least-cost combined generation and transmission facilities.  Unlike in traditional Baseline Reliability Project planning, dispatch cases should not simply be taken as given, but rather should be seen as the starting point for analysis that can yield insights into which resource development patterns are most economical. 

• Finally, we emphasize that it is critical that the LRTP process focus not merely on addressing identified LRTP reliability issues, but on addressing them with the most cost-effective set of upgrades.

2. How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

• This question refers to “the system-level reliability component of LRTP projects.”  We interpret this to mean only the project cost remaining after costs are first assigned to a number of relatively clearly identifiable cost-causers and beneficiaries, and our support for the concept of a “system-level reliability component of LRTP projects” is contingent upon this interpretation.  Specifically, we anticipate that LRTP-project cost allocation will include the following elements:

• The LRTP-study futures include significant new generation whose interconnection will likely require transmission upgrades.  Accordingly, some portion of LRTP project costs is attributable to new generation interconnection, and cost allocation should be designed so as to ensure that generation developers are allocated an appropriate share and—importantly—that they see the incremental cost impact of their generation siting decisions. 
• We support allocation of costs to beneficiaries on the basis of quantified economic benefits, including avoided BRP costs.
• Costs required to address local load-pocket situations should be assigned locally.
• It would be reasonable to consider allocation of costs associated with satisfying public policy goals to loads in the corresponding jurisdictions.   
3. What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

• WPPI is satisfied that the existing MEP benefit metrics are appropriate and quantifiable with reasonable precision.  For this reason, we support continued use of these metrics.  We are open to considering use of additional metrics, but not currently persuaded that additional metrics are both significant and feasible to estimate with reasonable precision, which we see as prerequisites to adding them.

4. What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

• WPPI is comfortable with the 100 kV minimum cost proposed by the Certain TOs.  Projects with voltages down to 100 kV may be part of cost-effective solutions to issues identified in the LRTP analysis, and should be considered. This voltage threshold also encompasses the bulk of transmission facilities in MISO, and excludes only relatively minor facilities whose upgrade we believe can be left to the TO. 

• WPPI suggests not establishing a minimum cost threshold for LRTP projects as we expect both large and small projects will have a role to play in cost-effectively increasing the ability of the transmission system to transfer power, and that addressing existing congestion problems without identified solutions is a logical component of long-range planning.  We are concerned that establishing a minimum cost may thus interfere with development of a cost-effective comprehensive long-range plan.

5. Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

• As noted in response to Question 2, it is important that generation developers see the cost impact of their siting decisions, which does not appear to be addressed currently in the Certain TOs' proposal. WPPI suggests one possible approach would be to apply a generator interconnection screen and leave out of the LRTP projects likely to be required to accommodate generator interconnections.  Another approach would be to include such projects in LRTP but carve out a cost allocation component for new generator interconnections.  Both of these approaches have drawbacks and will benefit from discussion, and others may be available as well.

PSCW Responses to May 12, 2021 RECBWG LRTP Cost Allocation Proposal

Opening Remarks:

As has been the case for the last century, society’s and our economy’s reliance on electricity will continue to increase in the decades to come. The tolerance for outages will likely continue to decrease, and the cost of outages will likely continue to increase.  At the same time, transmission will not be the only technology used to solve for higher Reliability.

Studying whether, and which, transmission projects can cost-effectively solve Reliability issues over the next 20 years is prudent and PSCW staff supports LRTP as long as it is transparent and rigorous, understanding that some “art” will likely be needed at the end of the process.

PSCW staff remains concerned about the LRTP timeline. In any timeline, transmission problems must be clearly defined and the solutions rigorously and transparently analyzed. As this process continues, PSCW staff value transparency in information and ability for staff to rigorously review each grouping of projects, and a full stakeholder discussion of an appropriate and resilient cost allocation.  We must balance the concept of “first-mover” transmission expansion projects through LRTP in MTEP 2021 with a goal that the initial set of projects and cost allocation methodology should be durable for the many future years over which LRTP projects are envisioned to be proposed.

1. How would you define system-level reliability in the context of the projects identified through the LRTP process? Why? (see slide 8)

At the April 30, 2021, LRTP Workshop, MISO Staff seemed to indicate meeting NERC standards would be the Reliability measurement of LRTP.  MISO staff explained that meeting NERC standards over the next 20 years with a changing generation mix is the challenge and driving factor for the LRTP process, and that existing Transmission planning processes and tariffs do not address a 20-year outlook.

                                                               i.      Under this context, PSCW staff understands Electric System “Reliability” is typically defined as meeting NERC criteria or transmission system availability 99.96% of the time

                                                             ii.      Therefore, to the extent the changing generation mix or other changes are causing or would cause a NERC Reliability violation that LRTP projects can clearly resolve, then perhaps a separate “system-level reliability” definition is not needed.

1. However, if these changes will cause Reliability issues over the next 20 years for which NERC standards do not exist or suffice, then additional definition of these nascent Reliability issues may be needed as they relate to LRTP.  Currently, PSCW staff cannot identify an accepted definition of “reliability” beyond applying NERC criteria in transmission planning at MISO or for the LRTP process and this should be agreed upon before extending the definition of “system-level” reliability.
2. PSCW staff urges MISO and stakeholders to define terms and strive for as much clarity as possible, as early in the process as possible, as a productive foundation for this continued LRTP process.
3. Particular questions PSCW staff have around this topic include:

                                                               i.      How might the definition of reliability change over time?

                                                             ii.      Does reliability in MISO transmission planning already include other considerations around society’s increased reliance on electricity and low tolerance for outages?

 2.                   How should costs associated with the system-level reliability component of LRTP projects be allocated? Why? What is the appropriate level of granularity in allocating these costs (cost allocation zones, sub-regional level)? Why? (see slide 12)

1. 1. The guiding principle should remain “beneficiaries pay,” subject to accepted metrics and reasonable granularity. Any alternative risks unfair cost allocation, with adverse consequences.
   2. Within the current planning process, PSCW staff believe cost allocation should begin with ensuring accurate modeling prior to project approval at MISO. This should include timely sharing information with technical staff for analysis to check model accuracy and using such accurate or corrected modeling to identify beneficiaries under a beneficiaries pay approach.
   3. With this in mind, project costs may be allocated within an existing cost allocation category where it makes sense or under a sub-regional cost allocation to be determined (as described in the OMS Cost Allocation Principles for Long-Range Transmission Planning Projects).
   4. Before any form of postage stamping is chosen, other alternative cost allocation methods must prove ineffective at capturing benefits that cannot otherwise be quantified.
   5. Where appropriate, projects may provide benefits outside the region. MISO should explore whether/how some costs can be allocated or charged to imports from the region. Under this same line of thinking, MISO should review what improvements to market pricing or exports are possible to capture any of these cross-region benefits within FERC rules and/or identify what would require FERC policy changes.

                                                               i.      This could include evaluation within the LRTP process of a “Generators Pay” concept. Since there is no defined path for this concept in current LRTP discussions, PSCW staff does not yet have a position toward this.

                                                             ii.      However, the following concepts could provide insight into the process:

1. Proposed privately owned transmission (Grain Belt Express and SOO Green lines) will have generators, shippers, and off-takers paying directly.  These projects may provide ideas that could be incorporated into a Generators Pay component of LRTP should that be pursued further.
2. To the extent that a generator could connect to the grid, but would have production curtailed during some hours, a “Generators Pay” component could work to allow the Generator to compare apples-to-apples options of a) paying for transmission to move curtailed power or b) investing in energy storage to store previously curtailed power for delivery at another time.

 3.              What economic metrics should be used for allocating the economic component of LRTP projects? Why? Please include how any proposed metrics should be analyzed and quantified, and the appropriate level of granularity in allocating costs (cost allocation zone, sub-regional level, etc.) (see slide 11)

 PSCW staff does not yet have a position toward specific economic metrics. However, PSCW staff would point to the 2019 RECBWG straw list of metrics as part of the MEP process as a potential starting point for identifying any additional metrics, on top of the currently accepted MEP metrics.

 4.                   What project criteria should be used for LRTP projects, including minimum project cost, voltage, etc.? Why? (see slide 9)

1. 1. PSCW staff would need further clarification in general from the LRTP process on how sub-regional cost allocation zones could be determined and whether they would be derived from the current groupings of cost allocation and transmission pricing zones or other methodology before proposing a sizing requirement under the project criteria. This is because the voltage size of a line can be inherently linked to the allocation of benefits across a region or sub-region (i.e. the higher the voltage, the more likely multiple zones will identify benefits). However, PSCW staff also recognizes that in certain instances, a smaller voltage line could potentially have extensive regional or sub-regional benefits identified.  
   2. An important criteria for PSCW staff is the ability to review LRTP projects at periodic intervals and reevaluate future projects based on that analysis. For instance, any new set of projects should reconsider the first or previous layers of LRTP or other projects approved in MISO’s cyclical transmission planning process or related interregional processes.
   3. PSCW staff recognizes that policy and energy forecasts change more rapidly than these solutions can be planned and implemented/constructed given the typical long planning horizon for transmission projects. On the other hand, because the transmission planning horizon is understood in the industry as most accurate within a 10 year timeframe, projects after that point can be difficult to predict due to unclear or limited inputs. This reinforces the significance of reevaluation of projects potentially approved beyond that 10 years, especially where other projects are completed in that 10 year window.
   4. These criteria are even more important if the MISO RECBWG is unable to approve a specific or new cost allocation ahead of the first set of LRTP projects. We have concerns that a new or specific cost allocation for LRTP will be difficult to agree upon for “first mover” projects that are still to be proposed and potentially approved this year (by end of 2021).

 5.                   Are there other elements not contained in the proposal by Certain TOs that should be considered?  Do you have a better way for costs associated with projects identified through the LRTP process to be allocated? Please be as specific as possible, including how benefits should be calculated and how costs should be allocated (cost allocation zones, sub-regional level, etc.).

1. 1. Transmission alternatives including energy storage, distributed energy resources, and demand response must be regularly analyzed and annually re-analyzed and evaluated and compared to proposed transmission solutions.
   2. PSCW Staff continues to support and suggest an overarching capital planning approach to transmission planning, rather than the bucket/category approach currently used, in order to better analyze alternatives and provide increased assurance to stakeholders that transmission projects are indeed the best solution for the identified problem.
   3. MISO and Stakeholders should analyze the potential cost savings and performance of competitive procurement of transmission, based on the experiences in MISO and outside of MISO for competitively procured transmission projects in prior years.  If $30 - $100 billion is potentially to be spent on transmission, we owe it to ratepayers to ensure these funds were prudently spent. 

                                                               i.      For this study of potential savings from competitive procurements, the problems to be solved should be clearly identified, and non-transmission alternatives should be eligible to bid.

                                                             ii.      The characteristics of a competitive procurement process can be further developed in the MISO stakeholder process, including FERC compliance, use of existing right-of-ways, how to apply the process, etc.