RASC: Reliability Based Demand Curve Proposal and Design Elements (RASC-2019-8) (20221130)

American Municipal Power (AMP) appreciates the opportunity to provide feedback on the Reliability-Based Demand Curve proposal and design elements.

Advanced Fixed Resource Adequacy Plan (AFRAP) Requirements:

• More details are needed regarding the requirement for RERRA approval for AFRAP eligibility and what authority should be granted to state commissions or to RERRAs more generally. Often, municipalities and cooperatives are the RERRA. Additionally, there are times when things are reported to MISO as a single load, however, jurisdiction may reside with multiple RERRAs.
• The term resources as used in this context needs to be defined, for example, with regard to Distributed Energy Resources.
• Additional detail is also needed regarding where Demand Response resources are captured in the supply and demand curves.
• More details are also needed regarding the “Requirements” shown on slide 6 of MISO’s presentation, such as:
  • The term is shown as a minimum three consecutive years in or out. Are there additional details or limits on this requirement?
  • The amount of excess capacity LSEs can sell above their requirement. On slide 6, it is noted that this percentage is yet to be determined.

• Is there a cap on the amount of capacity that could be included in an Advanced FRAP in order to ensure that any residual load in the PRA can be served with economically competitive and operationally efficient capacity?

Net CONE Methodology:

• MISO is proposing using three years’ worth of historical data to determine inframarginal rents as part of the Net CONE methodology.
  • Has a forward-looking Net CONE been considered, or will it be considered?
  • How was the term of three years determined for historical data? Is there significance in this number being three versus another number of years?
  • Currently MISO has a pre-defined methodology and procedure to determine CONE for each LRZ. In determining Net Cone, MISO stated inframarginal rents will be determined on a regional basis. In this context, what is the definition of “regional basis?”

Auction Co-Optimization:

• The term “co-optimization” needs to be better defined since it appears the term has a specific and different meaning in the Energy and Operating Reserves Market.
• When performing co-optimization of resources, need to ensure the level of granularity at the LRZ level is appropriate, and not too small or too large.

Marginal Reliability Impact (MRI) Curves:

• More details are needed regarding the MRI process on slide 12, such as:
  • How is load (pt A) determined? Is MISO aggregating LSE forecasts to develop the demand curve?
  • What is the definition of “perfect” capacity” used in this context?
  • The angle of the slope for the RBDC is critical. It would be helpful to better understand what data was used for the points of the curve in the conceptual drawing of the curve on slide 13. If actual data was not used, it is recommended that a curve be developed based on actual data. Also, does the curve ever intersect the x axis?

General Comments:

• Is MISO working with a consultant on the RBDC proposal and design elements?
• Will a review process be included as part of an implementation plan to allow stakeholders the opportunity to review the demand curve’s performance and CONE on a periodic basis?

Michigan Public Power Agency (MPPA) supports the feedback submitted by WPPI Energy.

Vistra Corp. (“Vistra”) appreciates the opportunity to submit feedback on the Reliability Based Demand Curve (RBDC) proposal and design elements that MISO shared during the November 30^th RASC meeting; we look forward to additional discussions and workshops on this topic. Vistra strongly supports MISO’s stated goal of ensuring a RBDC is implemented in time for the 2024-2025 Planning Resource Auction (PRA) and believes a properly developed sloped demand curve will reflect the reliability value of surplus resources in excess of the minimum clearing requirement. Importantly, a RBDC will provide more accurate and stable price signals compared to MISO’s existing vertical demand curve where small surpluses produce near-zero prices, and small shortages push prices to the price cap-- as witnessed during the 2022-2023 PRA.

 As detailed in the above-mentioned MISO RBDC presentation, Vistra has no initial concerns with the concept of the Advanced FRAP (AFRAP) option--this requires an LSE to receive their respective state regulator’s approval for participation, and then fulfill their full load obligations outside of the PRA for three consecutive years. Vistra believes that a properly designed AFRAP, along with the traditional FRAP and the PRA, could improve the overall health of the MISO market. 

RBDC FEEDBACK ON BEHALF OF THE STAFF OF THE LOUISIANA COMMISSION

          This feedback is submitted on behalf of the Staff of the Louisiana Public Service Commission (“LPSC Staff”) to the MISO request for feedback to the reliability-based demand curve proposal and design elements made at the November 30, 2022 RASC meeting.

1. The LPSC Staff supports reliability under normal and extreme operating conditions.  However, because MISO has presented no analysis demonstrating the impact of its proposal on incenting new capacity and delaying the retirement of existing capacity, the LPSC Staff does not have the information needed to determine the efficacy of the MISO RBDC proposal on reliability. 

2. It is clear that the MISO proposal will have cost consequences on retail customers due to the shift in clearing quantities to the right of the .1 LOLE costs PRMR and by shifting costs from long LSEs to short LSEs.  However, MISO has presented no analysis demonstrating the impact of its proposal on costs and cost-shifting.  The LPSC Staff respectfully suggests that MISO re-run the 2022 PRA for the MISO subregions, including MISO South, with its new proposal in place, to provide insight to what the pricing would have been, and how costs would have been shifted.   In addition, the LPSC Staff would like to understand how the regional directional transfer limit will impact the RBDC changes and costs in Louisiana and MISO South.

3. The LPSC Staff seeks information and analysis regarding the impact that the RBDC changes will have on delaying expected retirements of generation, particularly coal generation in MISO.

4. The MISO proposal includes two factors to develop the formulation of the demand curve, including the marginal reliability impact and net CONE.  However, the MISO proposal regarding net CONE is not adequately developed or explained. It is respectfully requested that MISO address the benefits that it believes net CONE will bring that are incremental to the use of the marginal reliability impact methodology and how the two methods will be used in combination.  Absent such analysis and information, the LPSC Staff opposes use of the net CONE concept alone or in combination with the marginal reliability impact analysis.

5. The OMS November 2022 Initial Position Statement on the Consideration of a Revised Demand Curve in MISO’s Planning Resource Auction stated that the Resource Adequacy Construct “must continue to provide Load Serving Entities a mechanism to FRAP, self-supply, or otherwise opt out to meet their reliability needs.”   The LPSC Staff supported this language because that language sought a participation option that would allow PRA participants a mechanism to avoid increased capacity obligations and the uncertainty/volatility of any proposed sloped demand curve changes.  The LPSC Staff supports the retention of the existing PRA participation options, including the opt-out, FRAP, self-schedule, and price-sensitive offer options.

However, none of the existing participation options or the proposed AFRAP appear to allow a PRA participant to avoid the increased obligations or uncertainty.  Any new AFRAP or other alternative participation option should allow the LSEs to avoid the uncertainty and increases in load requirements and the uncertainty associated with accredited supply.  The three-year commitment requirement is inadequately explained and appears unnecessary.

The OMS Resources Work Group (OMS RWG) appreciates the opportunity to provide feedback to MISO on the Reliability-Based Demand Curve (RBDC) proposal and design elements. This feedback is from an OMS work group and does not represent a position of the OMS Board of Directors.

Advanced Fixed Resource Adequacy Plan (AFRAP)

The OMS RWG supports MISO’s attention to this element of the RBDC proposal, as getting this mechanism right is extremely important to many OMS members. As previously stated in the sixth bullet point of the Initial Position of the Organization of MISO States on Consideration of a Revised Demand Curve in MISO’s Planning Resource Auction (Revised Demand Curve Position): “The Resource Adequacy Construct must continue to provide Load Serving Entities a mechanism to FRAP, self-supply, or otherwise opt out to meet their reliability needs.” The OMS RWG offers the following thoughts on MISO’s initial AFRAP proposal.

• The OMS RWG supports MISO’s proposal to retain the existing options (FRAP, self-schedule, purchase from PRA, and opt-out) after shifting to the RBDC.
• If MISO moves forward with requiring explicit RERRA approval for LSEs to utilize the AFRAP mechanism, the approval process needs to be designed in such a way as to minimize any administrative burden on each RERRA.
• For some RERRAs/states, a proper balance for this mechanism is important: an AFRAP option should exist, but it should not be structured so lucratively that all eligible LSEs opt to utilize the AFRAP over participating in the MISO PRA.
• For some RERRAs/states, being required to procure capacity above the 1-in-10 requirement is extremely problematic and is a non-starter.
• The OMS RWG understands that MISO proposes a requirement whereby LSEs electing the AFRAP option can sell excess capacity above their capacity requirement, plus x% (still undetermined). However, in any given year, the AFRAP capacity requirement for a particular LSE could be either higher or lower than the cleared margin percentage in the upcoming auction. The RWG notes the ambiguity inherent in the current proposal, as an AFRAP entity may be able to sell either the difference between the auction clearing reserve margin and the three-year average, nothing, or any excess above their requirement. As such, the RWG recommends that the RASC more fully explore this concept to understand the implications of these different options with respect to the “plus x%” variable.

Net CONE

The OMS RWG does not currently have any comments on this element of the RBDC proposal.

Auction Co-Optimization

To allow for stakeholders, including OMS members, to better understand this element, the OMS RWG requests that MISO provide a few examples to demonstrate what it is envisioning with co-optimization across the seasons.

Comments on Behalf of Iowa Office of Consumer Advocate Regarding RBDC Design

December 30, 2022

Members of the Resource Adequacy Subcommittee,

Iowa Office of Consumer Advocate (“Iowa OCA”) appreciates the opportunity to provide feedback to Midcontinent Independent System Operator (“MISO”) regarding the design improvement features of the residual capacity market clearing mechanism known as the Planning Resource Auction (“PRA”), presented during the November 30, 2022, Resource Adequacy Subcommittee (“RASC”) meeting. Iowa OCA is also supportive of MISO’s ongoing discussion pertaining to design features that are integral components of the Resource Adequacy Construct (“RAC”). Iowa OCA is limiting the scope of these comments to the ongoing discussion pertaining to the reliability-based demand curves (“RBDC”) and, as such, reserves its opinion on other features of the RAC, such as but not limited to the Advanced Fixed Resource Adequacy Plan (“AFRAP”),Net Cost of New Entry (“CONE”), Auction Co-Optimization, and Non-Thermal Accreditation that are also currently being discussed in MISO’s RASC.

Iowa OCA is generally supportive of the Organization of MISO States’ (“OMS”) November 30, 2022, initial positions, and echoes OMS’ sentiment that modifying and continually evaluating the current market design features of the resource auction clearing mechanism is extremely important for ratepayers. Iowa OCA agrees with OMS’ position that any MISO-proposed changes to design features of the RAC must be respectful of state and local authority on resource adequacy decisions and ensure reliability needs are met at a reasonable cost for ratepayers. Iowa OCA also supports OMS’ position that any RBDC design should properly value the reliability benefits of excess capacity and minimize market design failures related to potential over-procurement, reliability, and costs to ratepayers.

WEC Energy Group does not believe MISO’s proposal for an Advanced FRAP (AFRAP) alternative provides LSEs with the ability to opt-out of the Reliability Based Demand Curve (RBDC aka downward-sloping demand curve) consistent with the OMS’s Initial Position of the Organization of MISO States on Consideration of a Revised Demand Curve in MISO’s Planning Resource Auction (OMS RBDC Position). The OMS RBDC Position includes the statement that, “The RAC [Resource Adequacy Construct] must continue to provide Load Serving Entities a mechanism to FRAP, self-supply, or otherwise opt out to meet their reliability needs.” MISO’s AFRAP proposal fails to meet this principle.

First, while MISO’s AFRAP proposal is not subject to the RBDC it does contains language that, over time, will require LSEs that AFRAP to meet a reserve margin that is higher than the margin that represents the 0.1 days/year LOLE. The AFRAP proposal contains a provision that LSEs are required to meet a reserve margin that is based on 3-year moving average of the cleared reserve margin from past PRAs. In the long run, the cleared reserve margin from past PRAs will reflect the RBDC unless 100% of load AFRAPs every year. This provision is not a true opt-out but an indirect application of the RBDC to all load.

Second, MISO’s AFRAP proposal contains restrictive provisions for a minimum term of 3 consecutive years and no ability to AFRAP less than 100% of an LSE’s obligation. We do not believe this is consistent with the OMS RBDC Position. Currently, LSEs have the ability to FRAP or self-supply a portion of their reserve margin obligation, clear the remainder in the PRA and change their decision each year. Capacity additions and retirements are inherently lumpy. LSEs deal with year-to-year fluctuations in their capacity portfolio by clearing residual short or long positions in the PRA. We believe the OMS RBDC Position expects this flexibility to remain within an opt-out. LSEs should be able opt-out of the RBDC on a yearly basis and for less than their full obligation.

Regarding the design and shape of the RBDC, much more work and stakeholder discussion is needed. The proposal to design the RBDC based on net CONE is fraught with controversy regarding the Inframarginal rents subtracted from the gross CONE. Additionally, LSEs that clear capacity through the PRA are not entitled to the Inframarginal rents from that capacity and should receive a price signal that represents the full capacity cost. A lower net CONE price signal during capacity shortage or near-shortage conditions does not provide the proper incentive for LSEs to acquire capacity.

To the extent that MISO adopts some form of sloped demand curve, WPPI finds it reasonable:

• to adopt a curve shape based on Marginal Reliability Impact, as described in MISO’s presentation; and
• to use an anchor point based on net CONE and the capacity quantity corresponding to 0.1 LOLE.

It may be appropriate to truncate the Demand Curve at some suitably high capacity level and low price.  We caution that significant year-to-year volatility of Net CONE could be problematic—even under MISO’s proposed 3-year average approach—and that it may be necessary to take additional steps to address such volatility.

WPPI is open to considering optimization of capacity acquisition across seasons.  We anticipate that this may be complicated and caution that increasing complexity may pose difficulties for both MISO and PRA participants.  WPPI is also open to accommodating an annual commitment.  Indeed, we took the position in 2021 that it was perfectly feasible to account for season-specific resource-adequacy concerns within an annual construct, and we still believe this to be the case.

We appreciate MISO’s proposal of the AFRAP mechanism as an effort to provide LSEs certainty with respect to their load obligation (share of PRMR).  MISO’s proposed restrictions on use of this mechanism, however (minimum term, no partial AFRAP), limit the utility of this option.  Particularly given the Capacity Replacement Requirement included MISO’s latest capacity-construct changes, Resource Owners are likely to have the need to offer some portion of their resources at a significantly non-zero offer price in many seasons.  We understand that this would foreclose use of AFRAP. 

It appears that it may be possible for those LSEs willing to jump through the necessary hoops to circumvent these restrictions via pre-PRA bilateral capacity transfers to third parties.  This calls into question the value of the no-partial-AFRAP provision, and we ask MISO to more clearly describe the underlying motivation and also to reconsider these proposed restrictions altogether.

Comments

of the

Association of Businesses Advocating Tariff Equity (ABATE),

Illinois Industrial Energy Consumers (IIEC),

Louisiana Energy Users Group (LEUG),

Texas Industrial Energy Consumers (TIEC),

Coalition of MISO Transmission Customers (CMTC),

Midwest Industrial Customers (MIC),

and

NIPSCO Large Customer Group (NLCG)[1]

Regarding

RASC: Reliability Based Demand Curve Proposal and Design Elements

(RASC-2019-8) (20221130)

December 28, 2022

ABATE, IIEC, LEUG, TIEC, CMTC and MIC, as representatives of the End-Use Customers (EUC) Sector, and NLCG appreciate this opportunity to provide comments to MISO.

At the November 30, 2022 meeting of the MISO Resource Adequacy Subcommittee (RASC), MISO provided its preliminary proposal and work plan to modify the demand curve of its Planning Resource Auction (PRA) for capacity.

MISO currently acquires a fixed amount of capacity in the PRA to meet the Planning Reserve Margin Requirement (PRMR) and Local Clearing Requirement (LCR) for each Local Resource Zone (LRZ) regardless of price.  MISO is proposing to modify the PRA such that the amount of capacity it acquires to meet the PRMR and LCR of each LRZ is a function of price.

Specifically, MISO is proposing to change the PRMR and LCR demand curves for the PRA from being a vertical curve, where the quantity of capacity acquired by MISO is a function purely of need and not a function of price, to a convex downward sloping curve where MISO would essentially: (i) acquire more capacity than is necessary to meet the PRMR and LCR of each LRZ when the intersection price with the capacity offer curve is less than the  MISO Cost of New Entry (CONE) price, and (ii) acquire less capacity than is necessary to meet then PRMR and LCR of each LRZ when the intersection price with the capacity offer curve is greater than the MISO CONE price.  This would have the effects of: (i) administratively inducing a higher Auction Clearing Price (ACP) into the PRA when there is a surplus of capacity offers in the PRA, and (ii) potentially allowing the ACP to rise to a much higher price than the CONE price when there is a deficit of capacity offers in the PRA.

MISO’s proposal could potentially lead to earlier new market entry by merchant capacity resources by offering a higher and more stable ACP than can be provided under the current PRA.  This could potentially reduce the risk of the PRA not acquiring sufficient capacity for MISO to on average meet MISO’s Loss of Load Expectation (LOLE) target of no more than one firm load curtailment day in ten years. 

However, it is important to note that no analysis has been presented at this point that conclusively demonstrates that adoption of MISO’s proposal would in fact produce that benefit and, if the expected new market entry does not occur, the outcome of MISO’s proposal could simply be to increase the market price for capacity for buyers within the MISO footprint without providing a commensurate benefit to those buyers.  Given this, the EUC Sector recommends that great care be taken by both MISO and its stakeholders in considering MISO’s proposal and whether it will actually produce the benefits that MISO and the MISO Independent Market Monitor (IMM) expect to be provided from the proposal.  

In addition, given that MISO is still in the middle of implementing its new seasonal resource adequacy and availability-based capacity accreditation construct and given that problems have recently been identified with respect to that construct potentially seriously overstating capacity need during shoulder seasons, we also recommend that any implementation of MISO’s instant proposal should not be scheduled to occur until there has been at least one run, without serious issue, of the MISO PRA under the MISO’s new seasonal resource adequacy and availability-based capacity accreditation construct.  The balance of our comments address specific concerns with MISO’s November 30, 2022 Presentation.

Untested Hypothesis

It appears the principal drivers of MISO’s pursuit of its proposal is the outcome of the 2023/2024 PRA for the North/Central Subregion, the MISO IMM’s long standing State of the Market Report recommendation that the MISO adopt a downward sloping demand curve for the PRA and the November 14, 2022 Initial Position Statement of the Organization of MISO States (OMS). 

The EUC Sector does not oppose examining whether the adoption of a downward sloping demand curve, either in the form of MISO’s proposal or some other form, would be effective with respect to reducing the risk of the PRA not acquiring sufficient capacity for MISO to on average meet the LOLE target of no more than one firm load curtailment day in ten years. 

However, the EUC Sector is greatly concerned that it appears that MISO has assumed that its proposal would be effective without conducting any analysis to evaluate whether its proposal would in fact be reasonably expected to do so.  The expected effectiveness of MISO’s proposal should not be assumed.  The expected effectiveness of the proposal needs to be reasonably demonstrated through analysis before a decision is made to file the proposal at FERC.

Selection of a Convex Demand Curve by MISO

Without supporting analysis and the receipt of feedback from stakeholders, MISO appears to have decided in its proposal to use a convex downward sloping demand like that of ISO New England rather than a linear downward sloping curve such as that used by the New York ISO and PJM.  The choice of the specific type of downward sloping demand curve should only be made after an analysis of the impact each type of curve is completed and stakeholders have been provided an opportunity to provide feedback on that analysis and the selection of the downward sloping demand curve type.

Compatibility with Fixed Resource Adequacy Plans and PRA Self-Scheduling Provisions

MISO in its proposal has unilaterally proposed to eliminate the ability of Load Serving Entities (LSEs) to self-provide all or a portion of their Planning Reserve Margin Requirement (PRMR) at a fixed Planning Reserve Margin percentage.  Essentially, LSEs would be permitted to designate capacity for a Fixed Resource Adequacy Plan (FRAP) or self-schedule capacity into the PRA to meet all or portion of their PRMR (i.e., their capacity requirement for their load), but, unlike under the current PRA, they would not know their precise PRMR prior to the PRA.  As a result, all LSEs would be forced to either purchase or sell capacity in the PRA depending on the final PRMR that is determined for them by MISO in the PRA.  This is very different than the current PRA and unacceptably introduces new price risks for LSEs that currently self-supply all or a portion of their PRMR.  MISO’s current FRAP and self-schedule provisions should be maintained such that all LSEs who choose to self-supply all or a portion of their PRMR know their PRMR for a FRAP or Self-Scheduling prior to the PRA and are not compelled to take on the risk of capacity purchases or sales in the PRA for the portion of their load for which they are proposing to self-supply capacity. 

MISO Advanced FRAP Proposal

It appears that MISO recognizes the aforementioned problems with its convex downward sloping demand curve proposal with respect to the use of a traditional FRAP given that MISO has proposed an optional Advanced FRAP mechanism.  Under MISO’s Advanced FRAP, LSEs would be able to know their PRMR prior to the MISO PRA in order to avoid the risk of capacity purchases or sales in the PRA.  However, they would have to place all of their load into the Advanced FRAP and remain in or out of the Advanced FRAP for a minimum of three years each time they choose to opt in or out of an Advanced FRAP.  Furthermore, only those LSEs that are deemed by their retail regulator as being eligible for the Advanced FRAP would be allowed to use it.

MISO’s Advanced FRAP proposal is highly problematic and not a substitute for maintaining the current FRAP and PRA Self-Schedule provisions with a known PRMR for self-supplying capacity prior to the PRA being performed.  The Advanced FRAP would unreasonably eliminate the ability of a LSE to self-supply a portion of its PRMR while floating the rest of its PRMR in the PRA.  In addition, MISO has not reasonably justified its proposal to allow retail regulators to be the “gatekeeper” of who is allowed to use the Advanced FRAP and who is not.   Retail regulators do not currently have a similar “gatekeeper” role over the use of a FRAP or self-scheduling by LSEs.  There is no basis for giving, or imposing on them, such a role for the proposed Advanced FRAP.

Compatibility with Michigan State Reliability Mechanism

Pursuant to Section 6w of Michigan Public Act 341 of 2016, the Michigan Public Service Commission (MPSC) has implemented an annual capacity demonstration process under which all electric suppliers in the State of Michigan are required to make an annual demonstration to the MPSC that they have acquired sufficient capacity to serve 95% of their expected PRMR in the MISO Planning Year commencing three years after the end of the current MISO Planning Year.  MISO has not addressed how its convex downward sloping demand curve proposal will interact with the MPSC capacity demonstration provisions and whether it would be compatible with them.

Timeline

MISO has proposed a very aggressive timeline under which it would file its convex downward sloping demand curve proposal with FERC by the end of the 2^nd quarter of 2023 for implementation in the PRA for the MISO 2024/2025 Planning Year, which will be conducted in April 2024. 

Given the number of questions that need to be addressed with respect to MISO’s proposal and the fact that MISO has yet to conduct its PRA without issue with its new seasonal resource adequacy and availability-based capacity accreditation provisions in place, we believe MISO’s proposed timeline is unrealistic. 

The proposed timeline should be revised to allow sufficient time to allow sufficient analysis, development and stakeholder review of the proposal before it is filed at FERC assuming that analysis, development and stakeholder support ultimately supports such a filing.  In addition, to allow the necessary time for the foregoing and to ensure any issues with the implementation of MISO’s seasonal resource adequacy and availability-based capacity accreditation construct are fully resolved, if MISO’s proposal is ultimately filed at FERC, it should not be implemented in the PRA prior to the 2025/2026 Planning Year.

Thank you for providing us an opportunity to provide these comments.  If it would be of help, we would be glad to discuss any of the above comments further with MISO and other stakeholders.  Please do not hesitate to contact any of the following representatives:

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

Kavita Maini

KM Energy Consulting, LLC (Consultants to MIC)

(262) 646-3981

kmaini@wi.rr.com

Southwest Louisiana Electric Membership Corporation (SLEMCO) agrees in principle with the direction MISO is taking on the development of a Reliability-Based Demand Curve (RBDC). SLEMCO concurs with the priority of improving capacity price signals provided by the Planning Resource Auction (PRA) to recognize the benefits of surplus capacity resources with the intent of rewarding capacity more appropriately and providing more transparent and stable PRA results going forward. SLEMCO would like to have MISO provide more detail and Stakeholder discussion to fully understand the implications of the Advanced Fixed Resource Adequacy Plan (AFRAP) proposal as to what the benefits and risks would be to an entity taking advantage of that option. Also, SLEMCO is supportive of the “net-cone” concept and its potential impact to better reflect the capacity pricing and needs in local resource zones (LRZs). Once again, more discussion and details are needed, specifically regarding new methodologies being developed to calculate the three-year rolling inframarginal rents on an LRZ basis. 

MPSC Staff strongly support the development of a downward sloping/reliability based demand curve and is generally supportive of the design elements contained within the November RASC presentation. However, MPSC Staff have several suggestions with regards to the AFRAP.

 Firstly, MPSC Staff questions the need for RERRA approval for LSE’s to select this option. We appreciate MISO’s commitment to preserving state authority but suggest that ‘RERRA approval’ may burden some Commissions, depending on the breadth of state processes or proceedings needed to give such approval. An alternative approach could be to require LSEs to notify the RERRA as part of the AFRAP selection process. The RERRA, as part of this process, should be given the ability to “object” to this selection, without requiring outright approval of the selection. This would provide a middle ground between respecting state authority and an approach like PJM’s Fixed Resource Requirement process, which does not require any such RERRA approval.    

 Secondly, it may be worth considering adding an additional component to the AFRAP Plan requirement for selling excess capacity. Under PJM’s FRR model, FRR entities may not sell surplus capacity into the capacity market unless they commit additional MWs to their FRR Plan above their capacity obligation. (PJM requires the lesser of an additional 3% of the FRR entity’s obligation or 450MW). If this additional quantity is met, then the FRR entity may sell excess capacity into the market. (the lesser of 25% of the FRR entity’s obligation or 1300MWs) (see Slide 11 here) Adding a similar option to the AFRAP would allow more flexibility for LSE to choose to either 1) Simply meet their capacity obligation or 2) include additional MWs in their AFRAP plan in order to sell excess capacity into the market.

Lastly, MPSC Staff strongly supports the minimum 3-year term, no partial AFRAP, and a limitation on selling excess capacity back into the market. These are essential elements to any AFRAP proposal.  

Xcel Energy appreciates the opportunity to provide feedback regarding the four design elements of the Reliability Based Demand Curve as presented during the November 30, 2022, RASC.  We are focusing on the Advanced FRAP and the calculation and use of Net CONE in our feedback.

Advanced FRAP (AFRAP)

MISO stated during the presentation that the value of the AFRAP would be to reduce uncertainty about the final obligation.  We question this as the requirement for the AFRAP is the maximum of the current PRMR or the three-year moving average of cleared margin percentages from past PRA.  Therefore, the obligation requirement will change annually within the three-year AFRAP commitment.  Since the RBDC will require additional capacity beyond the PRMR to be cleared, the three-year average is likely to be higher than the PRMR.  There could be instances in which the market clears in shortage (which would reduce the three-year average cleared margin percentage), but we expect those to occur rarely (especially after implementing the RBDC to mitigate that risk).  Therefore, it appears that the "uncertainty" from the additional obligation from the RBDC that is unknown until the PRA clears is less than the "uncertainty" from locking into a three-year commitment with shifting obligations and impacts from future revisions to capacity accreditation methods.   In addition, we ask that MISO address why it would be appropriate to charge LSEs that AFRAP for positive congestion and not credit for negative congestion.

Net CONE

Xcel Energy has serious concerns about MISO’s ability to appropriately calculate inframarginal rents for a lifetime asset with only three years of historical energy and ancillary service market revenue. Energy markets are inherently volatile so it is not clear how MISO will determine what a theoretical new entrant capacity resource would cost to operate, much less what they would earn in energy and ancillary services revenue over its lifetime.  If MISO wants the PRA to be a functional capacity market, it should not arbitrarily dictate a cap or an annual clearing target at net CONE, rather allow the market to determine the optimal clearing price and quantity for the residual load and capacity that participates in the PRA.  

Beyond the calculation of Net CONE, we also have significant concerns with MISO’s proposal regarding the application of Net CONE in the PRA. Slide 13 of the RBDC presentation implies that Net CONE will be utilized as an effective price ceiling in the PRA, but slide 26 notes that Net CONE is intended to represent the long term marginal average cost of a capacity resource – i.e., the “missing money” a capacity resource may not make up if not for capacity payments, and thus would not be induced to enter the market.  In short, we understand this to mean that the Net CONE value more appropriately represents the ideal average clearing price year over year for the market, over the life of an asset, not the appropriate price ceiling for the market.  However, MISO's presentation and stakeholder discussions did not make it clear if MISO intends to use Net CONE only in the Monte Carlo simulations to develop the demand curves or use it as an anchor point (as is done in NYISO and ISO-NE) or use it as the deficiency price in the market.  Using Net CONE as the deficiency price would not align with the economic principles under which the IMM originally proposed the RBDC and would likely lead to an ongoing risk of shortage in the capacity market. In other words, if CONE was a binding price ceiling in last year’s PRA, it will only exacerbate the issue to lower the deficiency price cap.

The Entergy Operating Companies ("EOCs")^[1] appreciate the opportunity to provide feedback on MISO’s Reliability Based Demand Curve proposal. 

Formulation of Demand Curve

MISO has proposed two concepts that should influence how the demand curve should be formulated: marginal reliability impact and net CONE. The EOCs support the use of the marginal reliability impact concept because it ensures that the cost of any incremental capacity that clears the PRA due to a sloped demand curve will be offset by an equal or greater benefit to customers in the form of reduced expected unserved energy. The EOCs do not fully understand how MISO is proposing to use Net CONE to inform the formulation of the demand curve and request that MISO provide greater detail on this point. Nonetheless, the EOCs are not convinced that net CONE should be used as a target auction clearing price for every year. This seems to presuppose that the PRA is short of capacity every year and that there is always a need for additional generation to be constructed. Lastly, the EOCs do not understand how both of these concepts (marginal reliability impact and net CONE) can be used in combination to influence how the demand curve should be created. Once a marginal reliability impact curve has been designed, any modification of this curve to achieve a desired net CONE clearing price outcome will result in a sloped demand curve that no longer accurately captures the relationship between customer’s value of lost load and the change in expected unserved energy. For this reason, the EOCs recommend that MISO pursue the marginal reliability impact approach and not try to incorporate net CONE considerations into the formulation of a demand curve.

Advanced FRAP (AFRAP)

The EOCs support a FRAP mechanism in the MISO market that allows LSEs to meet their reliability needs without being subject to the uncertainty and load obligation increase imposed by a sloped demand curve. MISO’s proposed AFRAP does not meet these objectives. The AFRAP proposal contains uncertainty related to an LSE’s load obligation and the quantity of accredited supply. The load obligation uncertainty is driven by the requirement that an LSE must commit to using an AFRAP for a 3-year term and that the load obligation across that term will continue to change based on the 3-year rolling average of PRM values that occurred in prior auctions.  The supply uncertainty is driven by the fact that an LSE will not know how much accredited capacity it will have over the 3-year term due to the volatile nature of SAC and uncertainty related to new build/retirement dates. Given the uncertainty related to both the load obligation and the accredited supply that exists with the AFRAP as proposed, there is real risk that an LSE that elects to use AFRAP could end up in a short position (fail to meet the AFRAP requirements) and end up having to pay the capacity deficiency charge of 2.7 x CONE, which would be a higher financial cost than any auction clearing price that could occur in the PRA. All of these factors taken in totality make the proposed AFRAP option unreasonable, unappealing, and unlikely to be used by LSEs, including the EOCs.

The EOCs believe that the new AFRAP option should allow an LSE to avoid the load requirements increase imposed by a sloped demand curve and that the new AFRAP option should provide certainty on both the load obligation and the accredited supply by removing the three year commitment period.

Finally, the EOCs have the following questions for MISO on the AFRAP proposal:

• What is the purpose of the AFRAP proposal including a 3-year term requirement? What problems would it cause if an LSE alternated across planning years between using AFRAP and participating in the PRA?
• Please explain in further detail the following MISO proposed AFRAP requirement: “LSEs can sell excess capacity above their requirement plus x%”

A slope demand curve without a change in the offer curve will not solve the issue of volatile capacity pricing in MISO.  The offer curve for capacity is such a sharp hockey stick, that even a sloped demand curve will likely have an issue setting a more stable price.  Without a changing of offers, volatility is likely to continue.  Participants have almost no incentive, or even ability to, to submit higher offers, and have the market reflect more stable prices.  Since the PRA functions as an imbalance market, if owners want to operate their unit, they have an incentive to offer a $0/MW-Day and get whatever money they can.  Owners that are long capacity and plan to offer, can only offer up to 10% of the LRZ''s CONE value without submitting additional paperwork (~$25/MW-Day).  The only participates offering above the 10% "safe harbor" rule are either retiring a unit or pursuing seasonal operation (under the old method).  As retirements take a while to plan, there are not a lot of those offers in the market. Realistically, without a change in offering behaviors, the PRA will have an issue with stable, and indictive price formation.