MSC: Cost Allocation Schedule 49 proposals (MSC02021-1) (20210415)

FEEDBACK FROM THE COUNCIL OF THE CITY OF NEW ORLEANS

TO THE MISO MSC FEEDBACK REQUEST REGARDING

COST ALLOCATION SCHEDULE 49 PROPOSALS

APRIL 29, 2021

At the April 15, 2021 Market Subcommittee (“MSC”) meeting, MISO gave an update on Schedule 49 and presented three alternative proposals for consideration to allocate Schedule 49 costs beginning in 2022. The three alternatives were described as the Load Ratio Share Method, the Market-Based Method, and the Planning Model (Flow-Based) Method. MISO requested feedback on these alternatives by April 29. 

The Council of the City of New Orleans (“Council”) provides the following feedback: 

1.         The Council is interested in reviewing more information related to the three MISO proposals and reserves on taking a position on its preferred approach at this time.

2.         If, however, MISO decides to pursue the Planning Model (Flow-Based) approach, the Council urges MISO to adopt the proposed revision to the Zonal Allocation.  Specifically, the Council supports a change from the current use of Local Resource Zones (“LRZ”) to the use of Cost Allocation Zones (“CAZ”).  Since the purpose of Schedule 49 is to regionally allocate costs (i.e., payments made under the MISO-SPP JOA Settlement), the Council believes the methodology should reflect CAZs that are also used to regionally allocate costs of Market Efficiency Projects approved through MISO’s MTEP process.  In contrast, LRZs are used for determinations related to the capacity requirements for MISO’s Resource Adequacy construct.  Further, the Council argues that, unlike LRZs, the use of CAZs aligns with the stated objective of retail regulators for cost allocation to be more accurate and granular to ensure that costs are properly assigned to beneficiaries.[1]

MGE supports WPPI Energy's feedback.  

And, for what it's worth, I'm aware of other stakeholders generally seeking more information and numerical examples to better understand Options 2 and 3.

David Sapper

dsapper@ces-ltd.com

Consumers Energy appreciates the opportunity to provide feedback regarding MISO's Cost Allocation Schedule 49 proposals (MSC02021-1) (20210415).

Consumers Energy recommends that MISO utilize Option #3 for the extension of the Schedule 49 cost allocation until a new settlement agreement with the Joint Parties is reached. The existing methodology (with the modeling change to replace the 5-year out PROMOD model with a current year model) appropriately allocates costs to beneficiaries and was developed with significant stakeholder discussion.

DTE supports a long-term solution to Schedule 49 cost allocation which assigns costs to beneficiaries.  In both options 1 and 2, a substantial portion of the costs are allocated based on different variations of a load ratio share, which seems to depart from this principle.  As such, DTE believes that option 3, with its annual calculation of adjusted production cost benefits based the actual system for that year, would represent the most accurate allocation of costs. 

At the April 15, 2021 MSC meeting, MISO gave a Schedule 49 update and presented for consideration three alternative proposals to allocate Schedule 49 costs beginning in 2022. The three alternatives were described as the Load Ratio Share Method (LRS) with two alternative calculations, the Market-Based Method, and the Planning Model (Flow-Based) Method. MISO seeks feedback on these alternatives by April 29. This feedback does not constitute a position of the OMS Board of Directors.

 The OMS MWG seeks additional information by presenting the following questions:

• With regard to Option #1 Load Ratio Share approach,
• Please provide an example calculation using recent historical data demonstrating how the Alternative 1 straight LRS calculation compares to the Alternative 2 calculation. In addition, please describe why and how Alternative 2 more accurately assigns costs to beneficiaries.
• For Alternative 2 and the allocation to each region, please explain the proposal to use “percentage of time” of importing vs. the percentage of the amount that was imported using recent historical data.
• For either “percentage of time” or “percentage of amount”, what is the period of measurement, e.g., day, week, month, year?

• With regard to the Option # 2 Market-Based allocation proposal, please answer the following:
  • If congestion is greater than the monthly Settlement Agreement charges, is the proposal to allocate the LRS charge portion of the RDT payment on a straight LRS basis comparable to Alternative 1 of Option 1? If not, please explain the proposal.  If yes, please explain how this more accurately assigns costs to beneficiaries?
  • If the congestion is less than the Settlement Agreement charge, what is the rationale supporting the assignment of all costs in excess of congestion to the importing region?
  • How is the RDT congestion determined?
  • What is the relationship between the RDT congestion and the settlement agreement payments?
  • When the RDT binds, why does MISO believe that the beneficiary pays too much? Who are the beneficiaries?
  • When the RDT does not bind, why does MISO believe that the beneficiary pays too little? Who are the beneficiaries?

• Please provide a sample calculation using recent historical data similar to that provided on page 5 of the MSC presentation for each of the proposed allocation methods, including both alternatives for Option 1.

• With regard to Option #3 (Planning Model), referring to page 10 of MISO’s MSC 4/15/21 presentation:
• Please describe in detail the drivers for the differences in allocations resulting from the use of the current year model vs. the five-year out model. For example, describe what the specific differences are in gas price assumptions, fleet, generation mix, topology, flowgates and any other drivers that are driving the large differences in allocations and benefits.
• Please explain the rationale and the reason for the potential change to the PROMOD import/export benefit allocation to assuming that all benefits go to the importing region. Provide all workpapers supporting that change.
• Please provide an analysis of the proposal to allocate future Schedule 49 charges on a Cost Allocation Zone (CAZ) basis showing the impacts that proposal would have had for Local Resource Zone (LRZ) 9 for the time period 2016-2020, if the CAZ allocation had been in place during that historic period (i.e., comparing the actual Load Ratio Share allocations within LRZ 9 against what the allocations would have been had CAZ 9, 11, and 12 been in existence at that time).

• Please explain why the five-year out model was utilized in the existing settlement agreement calculations and not with the current year model? 

• Please provide a chart similar to the confidential chart contained on page 11 of the MISO Schedule 49 settlement presentation dated March 3, 2021- for the MSC alternative proposals for all zones and for the years 2016 - 2020.

Ameren supports Option #2: Market based approach.   The market approach is preferred because it uses the congestion dollars collected and associated with the RDT to pay for or "offset" the RDT charges.  This is similar to how over collection of congestion on FTRs is handled and is a more logical approach to the market settlement aspects of Schedule 49.  Ameren also would support a market approach that would utilize actual market flows (using meter data) identified in the settlement process and then true up through the market settlement process like other market specific charges. (utilizing S14, S55 and S105 process).

Ameren does not support Option #1 because a load ratio share concept isn't consistent with identified beneficiaries paying the costs; especially in a case where actual flows can be determined.

Ameren does not support Option #3 because utilizing models, while useful in the planning process, should not be utilized when actual flows and meter data can be used to determine beneficiaries and may result in less accurate distribution of costs. 

Xcel Energy, Otter Tail Power Company, and the Entergy Operating Companies appreciate the opportunity to provide feedback on the three cost allocation proposals presented at the April 15 Market Subcommittee stakeholder meeting.

Xcel Energy, Otter Tail Power Company, and the Entergy Operating Companies  are concerned with the current Schedule 49 Settlement Agreement approach which allocates majority of flow-based costs to small number of Local Resource Zones (LRZs), while other LRZs pay nothing.  This disparity does not reflect that all load benefits from lower market prices.  For example, under the current Settlement Agreement, when the North was the importing region from 2016 and 2020, three of seven LRZs paid approximately 77% of the flow-based allocations while several zones did not pay any flow-based amounts.  Showing a similar pattern, when the South was importing, one LRZ in the South paid approximately 64% of the total flow-based amounts between 2016-2020.

Xcel Energy, Otter Tail Power Company, and the Entergy Operating Companies believe these types of issues arise with the current Schedule 49 Settlement Agreement because MISO is using a transmission planning model which does not align with what occurs in the market (transmission planning vs. transmission operations).  Xcel Energy, Otter Tail Power Company and the Entergy Operating Companies suggest MISO move away from the flow-based approach (Option #3) and instead implement a market-based solution (Option #2). 

As such, Xcel Energy, Otter Tail Power Company, and the Entergy Operating Companies encourage MISO to refine Option 2 with stakeholders. 

Xcel Energy, Otter Tail Power Company, and the Entergy Operating Companies note that if the cost allocation method for Schedule 49 is modified, MISO and stakeholders should also discuss if any refinements are also necessary to the Schedule 49 benefit metric for Market Efficiency Project cost allocation.

Finally, Xcel Energy, Otter Tail Power Company, and the Entergy Operating Companies suggest MISO discuss with stakeholders the appropriateness of an Evergreen solution for Schedule 49 prior to knowing the long-term agreement between MISO, SPP, and the Joint Parties for flows on the N-S constraint.  Depending on the outcome of the long-term agreement, Schedule 49 cost allocation may or may not need to be revisited.

At the MSC on 4/15/2021, MISO provided 4 options to allocate Schedule 49 costs, which is payment to SPP and the Joint Parties for flows above the 1000 MW contract path between MISO North/Central and MISO South (Item 07 Schedule 49 Cost Allocation Update). At this early stage of the discussion, WPPI is not prepared to support any particular option(s), but we offer the following feedback and requests for more information in order to inform WPPI’s eventual selection of an option(s):

(1.) Please provide the cost allocation results (on a Local Resource Zone basis) under each of the proposed options for each of the last 5 years. All other factors equal, WPPI’s main criterion for a cost allocation methodology is whether it is just and reasonable (i.e., beneficiaries pay).

(2.) In selecting an option, it is important that it is just and reasonable not only today but in the long-term (i.e., evergreen). As a result, based on the information provided thus far, WPPI is inclined to incorporate into the cost allocation methodology the benefits accruing to both the importing and exporting sub-regions (vs. only the importing sub-region). Note: Sub-region is either MISO N/C or S.

(3.) In the cases of the options that do incorporate the benefits accruing to the importing (and perhaps exporting) sub-region, why is the percentage of time importing used vs. percentage of MWs imported?

(4.) Option 2, which depends on SPP/JP costs relative to congestion collected on the Regional Directional Transfer constraint (N/C to S, 3000 MW and S to N/C, 2500 MW).

• (a) Please explain further the logic behind this option (it is entirely unclear to WPPI why MISO assesses this option as beneficiaries pay “high”).

• (b) How does this option take into account the difference in the ability of the two sub-regions to import/export above 1000 MW?

• (c) How does this option take into account the difference in the total load between the two sub-regions (N/C, ~73% and S, ~27%)?

(5.) Option 3, replace 5 year out economic planning model in the current cost allocation approach with a near term economic planning model.

• (a) At this point, WPPI favors option 3 because it provides a clear basis (unlike option 2 thus far) for identifying beneficiaries. Specifically, the economic planning model is used to determine the change in Adjusted Production Costs as a result of flows above 1000 MW on the RDT.

• (b) As noted in item (2), WPPI is inclined to allocate costs to both the importing and exporting sub-regions based on their relative benefit.

• (c) Explore whether the LRZ percentages should be different depending on whether a sub-region is importing or exporting.

MidAmerican Energy Company appreciates the opportunity to review and comment on the Schedule 49 cost allocation methodologies.

MidAmerican agrees with MISO that the Schedule 49 methodology should not be overly complicated and should remain consistent over time. We also believe that costs should be allocated commensurate with benefits.

MidAmerican supports Option 1 (load ratio share), because it is the most appropriate way to allocate the Schedule 49 costs of the allocation methodologies currently proposed. MidAmerican specifically supports Option 1, alternative #2, because it appears simple, remains consistent over time, and assigns costs to the beneficiaries appropriately. This approach will also not have any corollary effects on the market, will not be an undue burden on MISO staff, and will not produce results in conflict with the principle that the beneficiaries should pay.

MidAmerican does not support Option 3 (the planning model approach). MidAmerican is concerned that the use of any planning model will result in charges fluctuating drastically, and that maintaining the models would either be a very large burden on MISO staff or the models may be inaccurate to the point that the resulting costs will not be allocated to actual beneficiaries.

More clarity on Option 2 (the market-based solution) is necessary for stakeholder consideration since this methodology has not been used previously. It appears that MISO would collect revenue from the market similar to how a Financial Transmission Right (“FTR”) option would work. For this to work properly, MidAmerican understands that there would need to be the FTR option in both directions. MidAmerican would like to understand how this would impact other parts of the market. Would this cause underfunding of the FTR market?

WEC Energy Group recommends that MISO pursue Option #3 for the extension of the Schedule 49 cost allocation until a new settlement agreement with the Joint Parties is reached, which will trigger another review of Schedule 49. Option 3, which consists of the existing 10% LRS and 90% benefits-based and the replacement of the 5-year out PROMOD model with a current year model, improves upon the existing methodology by utilizing a model with a topology more representative of the current year.

While the other options may have merit, the existing methodology (with the modeling change) appropriately allocates costs to beneficiaries and was developed with significant stakeholder discussion. Evaluation of all Schedule 49 cost allocation options is required to incorporate the specifics of a future renegotiated settlement with the Joint Parties.