RASC: RBDC Proposal (RASC-2019-8) (20230711-12)

Grid reliability is of utmost concern to the Indiana Utility Regulatory Commission (IURC) and, therefore, the IURC continues to support MISO’s initiative to implement a reliability-based demand curve (RBDC). Based on presentations made to date, the IURC believes that the initial regional RBDC curves are reasonable and thus support the draft tariff language insofar as it aligns with the proposal.  The IURC offers no comment at this time regarding the specific RBDC opt-out proposals under consideration given that the existing options (opt-out, FRAP, self-schedule, price sensitive offer) remain available to LSEs.

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 July 11^th RASC meeting; we thank MISO Staff for their hard work to advance this concept and look forward to future discussions on the RBDC. As highlighted by the recent 2023 OMS-MISO survey results, which indicate a rapid decrease in committed capacity in the next few years, there remains an urgent need for the implementation of an RBDC in order to establish efficient capacity prices that will incentivize new generation and reduce the ever-increasing reliability gap. The efficient price signals that result from the RBDC will also assist market participants with resource retirement decisions, including reducing uneconomic retirements in the MISO region.

Vistra strongly supports MISO’s current plan to submit an RBDC tariff filing to FERC before the end of Q3 2023. We believe this timeline helps ensure that the RBDC is finalized and implemented ahead of the 25/26 PRA. Vistra also supports MISO’s decision to separate the ‘co-optimization with multi-season block offer’ concept from the RBDC filing. Based on the lengthy discussions on this topic during multiple RASC meetings, stakeholders still have a number of questions and concerns with this concept, and it will be helpful to focus on that topic after the RBDC process is completed. Vistra continues to believe that the co-optimization proposal is at odds with the FERC approved, and recently implemented, seasonal resource adequacy construct, but are happy to address those concerns in future MISO stakeholder meetings.

Below, Vistra proposes several adjustments to the draft RBDC tariff language that MISO shared with stakeholders during the July RASC meeting. In general, we encourage MISO to strengthen and clarify the new definitions that are included in the proposed tariff filing. Vistra recommends that MISO review the more comprehensive definitions that other RTOs such as ISO-NE and NYISO have adopted to define the development of their sloped demand curves. Many of MISO’s new RBDC definitions are terms already defined in other RTOs and have been carefully vetted during the stakeholder process. By studying existing definitions, MISO may help eliminate or at least reduce any future uncertainties or disputes regarding the development of, or updates to, the RBDC.   

 “New Module A Definitions” Draft Tariff Language

• Comments on “Marginal Reliability Impact Curves” and “Reliability Based Demand Curve” Definitions
  • It would be helpful if the definitions for “Marginal Reliability Impact Curves” and “Reliability Based Demand Curve,” included language focusing on the improved reliability price signals that the curves will provide. For example, MISO should consider stating that the MRI Curves are ‘downward sloping curves that reflect the expected improvement in reliability associated with adding incremental capacity. Under MRI Curves, prices increase as reserve margins decline, in order to provide the correct price signals and avoid low reliability outcomes.’ Similar information could be included with the Reliability Based Demand Curve definition.
    
    
• Comments on “Net Cost of New Entry” Definition
  • MISO should consider expanding and clarifying aspects of the proposed definition for “Net Cost of New Entry,” to avoid confusion and future challenges. For example, ISO-NE’s definition of Net-CONE is more detailed than MISO’s, and states that Net-CONE is “an estimate of the Cost of New Entry, net of non-capacity market revenues, for a reference technology resource type and is intended to equal the amount of capacity revenue the reference technology resource would require to be economically viable given reasonable expectations of the energy and ancillary services revenues under long-term equilibrium conditions”[1] MISO’s proposed Net-CONE definition would benefit from additional details, similar to ISO-NE’s definition, regarding what the Net-CONE calculation is intended to achieve.
    
    

“Reliability Based Demand Curve Procedures” Draft Tariff Language

• Vistra is supportive of MISO conducting their demand curve updates, including a reference technology review, every three or even four years, and has concerns regarding a more frequent review process. In other RTOs, demand curve updates are typically a time intensive effort that consumes the stakeholder process and can span many months. There have been instances when an extensive stakeholder process followed by contentious litigation at FERC has meant that as soon as the RTO has completed one demand curve reset process, the region is required to immediately turn to the next demand curve reset process.  MISO should consider a demand curve reset every three or four years, rather than a shorter period, to avoid this outcome.  An additional benefit of the three- or four-year demand curve review process is that it provides MISO and stakeholders with the needed time to focus on other initiatives and priorities.
  
  

“Calculation of CONE and Net CONE” Draft Tariff Language

• As part of MISO’s use of historic data to determine Net CONE values, Vistra would like to better understand if MISO plans to adjust historic Energy and Ancillary Services values for current and forward fuel prices. If not, Vistra would encourage MISO to ensure that current and future fuel prices are incorporated in Net CONE calculations, and that the historical data used for Net CONE does not rely on stale fuel prices for the Net Cone calculation.

Arkansas Public Service Commission’s Feedback 3/24/23

Feedback Request: MISO is requesting feedback on the reliability-based demand curve and Opt-Out provisions by July 28, 2023

Feedback Summary:

As described below, the Arkansas Public Service Commission (APSC) has concerns about the development of the downward sloping demand curve (now referred to as the Reliability Based Demand Curve or RBDC).  If MISO insists on proposing the RBDC for use in the Planning Resource Auction (PRA), MISO should use the Entergy Opt-Out.  MISO’s AFRAP and the current FRAP do not qualify.

THE RBDC SHOULD APPROXIMATELY REPRESENT CONSUMER VALUATION OF RELIABILITY

While the APSC is not opposed in principle to a downward-sloping demand curve, the APSC has some practical concerns about the development of the RBDC.  First, the RBDC should approximate as closely as possible the marginal value of reliability.  It should not just be an “administratively”- determined demand curve. 

Second, MISO has not provided sufficient data support for the scalar value used in the shift from the Marginal Reliability Impact Curves (“MRI”) to the RBDC.  That formula is:

(MWH/MW-yr.)*(1 yr./365) * ($/MWH) = $MW-day

where $/MWH is the scalar value apparently based on Value of Lost Load (“VOLL”).  Is there academic support, or survey support for the VOLL value(s)?  Does it change over the seasons, or every year?  This scalar value is of major import since slight changes in that scalar value can result in large changes in in the Clearing Price in the Planning Reserve Auction because of the inelastic nature of the Supply Curve.

Third, MISO refers to a preference for convex demand curves because it reflects the incremental reliability to consumers of additional capacity.  However, note that decreasing marginal value of reliability is reflected in concave, straight-line, and convex demand curves. If the data show that the RBDC is convex, and representative of consumer valuations, that is fine.  However, there should be no a priori justification of a convex RBDC.

Unless, the issues are adequately addressed, the APSC will likely not support a downward-sloping demand curve.

THE ENTERGY OPT-OUT IS REASONABLE IF THE RBDC IS IMPLEMENTED

If MISO insists on proceeding with RBDC implementation, a reasonable Opt-Out Option is required.

MISO’s AFRAP option does not meet the requirements of a reasonable n Opt-Out Option. Neither MISO’s AFRAP nor the existing FRAP allow an LSE to avoid increases in its capacity obligation under a RBDC. Combined with the impacts from MISO’s SAC proposal, the increase in capacity requirements could impose significant negative cost consequences on many customers, without sufficient demonstrated benefit.

The APSC supports the AFRAP proposed by Entergy.  It provides a reasonable compromise among the various parties’ interests. Providing the Entergy Opt-Out Option will ensure that those states/LSEs that choose to participate in the PRA with a RBDC are free to do so, and those that choose not to fully participate need not.  If states/LSEs agree that the PRA is beneficial, they will likely participate.

North Dakota believes that the 1-in-10 reliability standard should be maintained as a minimum requirement and not be an average target. The construct should incent outcomes that avoid clearing with a capacity shortfall.

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),

and

NIPSCO Large Customer Group (NLCG)[1]

Regarding

RASC: RBDC Proposal (RASC-2019-8) (20230711-12)

July 28, 2023

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

We have reviewed MISO’s July 11-12, 2023 MISO Resource Adequacy Subcommittee (RASC) Reliability Based Demand Curve (RBDC) Proposal Presentation as well the draft tariff language that MISO posted on July 14, 2023 for its RBDC proposal, and we submit the below comments on certain aspects of the proposal.   As discussed herein, we strongly oppose MISO’s new proposal to eliminate the current 1.75X Annual Cost of New Entry (CONE) Price Cap on combined seasonal Planning Resource Auction (PRA) results along with its associated shortage and near-shortage pricing provisions.

Our silence with respect to any aspect of MISO’s presentation or its posted draft proposed tariff language should not be interpreted as tacit agreement with that aspect of the proposal or the draft proposed tariff language.  In addition, ABATE, IIEC, LEUG, NLCG, TIEC and CMTC each respectively reserve their right to further comment on the proposal and the proposed tariff language.

MISO’s Proposal to Eliminate the Current 1.75X Annual CONE Price Cap on Combined Seasonal PRA Results

At the July 11-12, 2023 MISO RASC meeting, as part of its RBDC proposal, MISO for the first time proposed to eliminate the current 1.75X Annual CONE Price Cap on combined seasonal PRA results along with its associated shortage and near-shortage pricing provisions.[2] Elimination of this price cap and its associated shortage and near-shortage pricing provisions would allow the annual average Auction Clearing Price (ACP) for one or more Local Resource Zones (LRZs) to potentially rise to as high as 4X the annual CONE price rather than just 1.75X the annual CONE price.  This proposal of MISO is such a recent development that it is not reflected in the draft proposed tariff language changes that MISO posted on July 14, 2023.  MISO’s given reason in its RBDC presentation for the proposed elimination of the 1.75X annual CONE price cap and its associated tariff provisions is that “they are administrative and will not perform effectively under the RBDC”.[3]   

ABATE, IIEC, LEUG, NLCG, TIEC and CMTC strongly oppose MISO’s new proposal to eliminate the current 1.75X Annual CONE Price Cap on combined seasonal PRA results along with its associated shortage and near-shortage pricing provisions.

The 1.75X Annual CONE Price Cap on combined seasonal PRA results is a critical consumer protection that mitigates the degree to which the combined seasonal PRA results in any given LRZ can exceed the annual CONE price.  It also largely figured in FERC’s August 22, 2022 Docket No. ER22-495-000 and ER22-495-001 approval of MISO’s seasonal resource provision of less than one year ago to the point that FERC required MISO to make a compliance filing to clarify the language associated with the shortage and near-shortage provisions associated with the 1.75X Annual CONE Price Cap on combined seasonal PRA results.[4]

Furthermore, MISO itself, in its April 8, 2022 response to FERC’s deficiency letter in Docket No. ER22-495-000, indicated with respect to its 1.75X Annual CONE Price Cap on combined seasonal PRA results that:

“Under the existing construct, certain Resources are not available during the entire Planning Year. These Resources would still offer and clear for the entire year under the current annual construct. With the proposed move to a seasonal construct, MISO recognized the need to raise the daily offer cap so that Resources that are only available or only needed in a single Season are still eligible to receive payments up to annual CONE. While this continues to ensure revenue adequacy (without which a Resource can be exempted from having to participate in the auction as described above and as set forth in Section 64.1.1.g) it could lead to scenarios where load pays capacity charges in excess of Annual CONE. Without mitigation an LRZ that goes short in each Season could be subject to paying four times CONE. The proposal mitigates this result by reducing Auction Clearing Prices for shortage and near-shortage Seasons so that, in the aggregate, such Seasons collect up to Annual CONE but no more. The potential for charges above annual CONE comes from revenues based on ACP in Seasons that were not in shortage or near-shortage conditions which MISO is not mitigating. By definition, those prices will always be below the mitigated prices in the shortage and non-shortage Seasons, which MISO believes is a reasonable outcome.”[5]

MISO further indicated:

“MISO believes the proposal represents a reasonable balance between incentivizing PRA participation from Resources that are only available or only economic in certain Seasons while protecting load from paying capacity charges that, in aggregate, are well in excess of annual CONE.”[6]

The Commission ultimately accepted MISO’s proposal in ER22-495 based on the entire record in that docket, including the representations made by MISO in its April 8, 2022 response to FERC’s Deficiency Letter, that MISO’s proposal will reduce costs to consumers.[7]  MISO has failed to provide any explanation or analysis that shows why its RBDC proposal would eliminate the need for the consumer protection provided by the 1.75X Annual CONE Price Cap.  Until it is reasonably demonstrated that MISO’s RBDC proposal eliminates the need for the 1.75X Annual CONE Price Cap, the cap, and its associated shortage and near-shortage provisions, should be retained in the MISO Tariff.

Other Comments

In addition to the foregoing comments with respect to MISO’s proposal to eliminate the current 1.75X annual CONE price cap on combined seasonal PRA results, ABATE, IIEC, LEUG, NLCG, TIEC and CMTC would like to also note the following two typographical errors in MISO’s July 14, 2023 draft proposed tariff language:

• Section 69A.1.2 b: “Final RPMR associated with” should be “Final PRMR associated with”.

• Section 69A.7.1 b: “unless they opted out of the PRA pursuant to Section 69A.9” should be “unless they opted out of the PRA pursuant to Section 69A.9.1”.

Thank you for providing us an opportunity to provide the above 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

Ken Stark

McNees Wallace & Nurick LLC (for CMTC)

(717) 237-5378

kstark@mcneeslaw.com

The OMS Resources Work Group (OMS RWG) provides this feedback to MISO on its most recent update on the Reliability Based Demand Curve (RBDC) proposal. This feedback is from an OMS work group and does not represent a position of the OMS Board of Directors.

Opt-out provision

The OMS RWG appreciates MISO’s continued work to refine its proposed RBDC opt-out mechanism. We offer the following comments on the latest updates to the opt-out proposal.

The OMS RWG agrees with aligning the update of X% for the RBDC opt-out and the update of the RBDC curves. Having both items updated on the same timeframe ensures the greatest level of comparability. The OMS RWG requests any information or reasoning to support the decision to update these items on a three-year cycle (rather than a two-year or four-year cycle).

The OMS RWG agrees with the MISO’s approach to prohibit grandfathering of X%. Using a previous value for X% for some LSEs may no longer provide comparability to the updated RBDC curves.

The OMS RWG requests more clarity on how voiding the opt-out minimum term obligation will work. During the July 12 RASC meeting, MISO proposed that if the new X% is higher than the previous X% when the LSE first chose to use the opt-out, then those LSEs would have the choice to void the remaining years of their opt-out minimum term obligation. MISO’s examples did not account for a scenario where X% goes up some seasons and down in others, and we ask for MISO to clarify its intent if this scenario were to occur. The OMS RWG believe that if X% goes up in any season, the LSE should have the ability to void the remaining years on its opt-out obligation.

Initial regional RBDC curves

The OMS RWG continues to have concerns with the RBDC curves being designed in such a way that they meet the 1-in-10 reliability standard on average. As was made clear after the PRA results were released in 2022, state regulators have significant concerns over outcomes that results in the MISO region falling short of meeting the 1-in-10 reliability standard in any year. The RBDC curves need to be designed in a way where, at a minimum, the PRA clearing price for any affected portion of the MISO footprint that has insufficient capacity to meet the reliability standard is at the cap.

Draft Tariff language

The OMS RWG encourages MISO to provide to stakeholders as soon as practicable the complete set of draft Tariff language, including provisions that objectively describe how the X% will be determined. With the expectation of a FERC filing in the next couple of months, stakeholders will need and are entitled to sufficient time to review the Tariff language and confirm their understanding of how the proposal will work through engagement in the stakeholder process.

DTE appreciates the ability to provide feedback on the updates to the Reliability Based Demand Curve Proposal.

Overall, DTE is in favor of the creation of the reliability-based demand curve and encourages MISO to continue with the initiative. However, in the current state, DTE would not consider the opt out provisions proposed by MISO. The uncertainty of future accreditation values within the new SAC framework, combined with the required three-year opt-in period, and the high penalty for failing to meet the planning requirement obligations in future years, leads to significant risk that would eliminate MISO’s current opt-out proposal as a viable option.

Instead, DTE would support further conversations related to the Entergy Opt-out proposal as proposed in the July 12th RASC. Their proposal seems to be an effective compromise that would provide a viable avenue to respect state’s rights by providing an opt-out mechanism, without compromising the shape or purpose of the reliability-based demand curve.  

American Municipal Power (AMP) appreciates the opportunity to provide the following comments in response to MISO’s feedback request on the Reliability-Based Demand Curve proposal:

In the presentation to the RASC July 11-12, 2023, MISO stated that based on stakeholder feedback, they are evaluating options to separate the co-optimization with multi-season block offer structure filing from the RBDC filing.  AMP believes the RBDC filing is critical for facilitating efficient long-term decisions that satisfy reliability needs and reduce consumer costs. However, AMP believes that the co-optimization filing is also critical. Seasonal co-optimization is critical for effective RBDC design in guaranteeing the least cost solution across seasons and providing for more efficient clearing with better price signals and lower costs. AMP encourages MISO to consider making the co-optimization with multi-season block offer structure filing concurrently with the RBDC filing.

AMP does not have any additional comments regarding the proposed opt-out provisions, initial regional RBDC curves, of draft Tariff language.

The Entergy Operating Companies ("EOCs")^[1] appreciate the opportunity to provide feedback on MISO’s Reliability Based Demand Curve proposal. The EOCs believe that the RBDC alone is not sufficient to ensure reliability and ensure that each LSE procures reasonable long-term resources to meet its load obligations; rather, at a minimum, appropriate regulation of resource planning and a reasonable minimum capacity obligation are also needed.  However, the RBDC, if properly implemented, would improve the MISO PRA and provide helpful incentives, particularly to LSEs not subject to state regulation and to merchant generation owners, to help achieve reasonable market outcomes consistent with maintaining reliability over the long-term.

RBDC Opt-Out and AFRAP

The EOCs believe that MISO should implement an AFRAP mechanism that is consistent with the proposed framework presented by the EOCs at the July RASC meeting. As demonstrated by the results of the July RASC motion, this view aligns with the majority of MISO stakeholders. Please see the EOCs’ June RASC comments for further explanation on this topic.

Regional Sloped Demand Curves

The EOCs request that MISO provide additional explanation/examples on how the regional sloped demand curves will be used in the PRA. Will the MISO-wide RBDC curve be used until the RDT constraint binds and then the regional RBDC curves will be utilized?  Also, will MISO explain how their proposed use of regional demand curves compares to other RTOs that have implemented sloped demand curves on a regional basis? Lastly, this topic does not appear to be sufficiently described in the draft tariff language. The EOCs ask that MISO review the “Conducting the PRA” section of Module E-1 to determine if more description is needed on how regional sloped demand curves will be implemented.

Price Cap

The EOCS request more explanation as to why MISO feels that a 1.75 x CONE price cap is no longer need for the seasonal PRA and that a potential PRA outcome of 4 x CONE is reasonable. Given the significant cost impacts of this decision, the EOCs feel that this issue warrants further discussion and explanation in a future RASC meeting.

Illinois Commerce Commission (ICC) staff continues to support MISO’s efforts on the Reliability Based Demand Curve (RBDC). MISO’s new opt-out proposal gives states more choices in fulfilling their Planning Reserve Margin Requirement (PRMR), including maintaining state control over resource adequacy decisions, while also ensuring equity between states that participate in the Planning Reserve Auction (PRA) and those that do note 

However, the opt-out proposal should ensure that the “x%” states must withhold never becomes a negative number. The withholding percentage should never fall below zero, to maintain system reliability. In addition, MISO should provide states with that percentage as soon as possible. States need that information to make a fully informed decision about whether to pursue the opt-out mechanism.

Finally, MISO should provide more clarity on the seasonal RBDC curves. ICC staff was curious why if winter risk was increasing, the winter RBDC seemed so steep? How do planned outages, especially in the shoulder seasons, impact the shape of the RBDC curve? 

MMPA and SMMPA submit the following feedback:

Please provide more information about the specifics of “LOLE study” used to determine MRI curves, as well as the other methods used to derive sub-regional sloped demand curves.  What, in precise and complete terms, makes them sub-regional?  (MISO’s references to “regional” instead of “sub-regional” are confusing.)

Please explain the extent to which moving from regional to sub-regional auction demand curves will in and of itself (i.e., ignoring other rule or methodology changes) put upward pressure on PRM% and PRMR.

For multi-season offer rules still under development, please explain the extent to which MISO intends to minimize uplift payment costs as it minimizes the total auction cost (i.e., auction revenues plus uplift payments). 

Please explain how the costs of multi-season offer uplift payments would be allocated.

Comments by the Environmental Sector 
Regarding MISO’s July 12, 2023 RBDC presentation

The Environmental Sector appreciates the opportunity to provide feedback to MISO regarding the proposed RBDC Opt Out provisions, initial regional RBDC curves, and draft Tariff language as they relate to the reliability based demand curve proposal and design elements. 

RBDC Opt Out Provisions

Firstly, we reiterate our belief that the Principle of ‘neither unfairly incent RBDC Opt Out nor force RBDC participation’ is vital to ensuring a just and reasonable RBDC Opt Out participation model. This Principle should also apply to any other participation model that may or may not be taken up by MISO. 

That said, while we understand that the intent of the adder is to promote equity between LSEs regardless of which option they choose, we believe that this interest is outweighed by the fact that the adder is unjustified from a reliability perspective. It requires consumers to buy more capacity than MISO's PRM indicates is needed for reliability, but without the justification that this tradeoff is an inevitable result of an otherwise beneficial sloped demand curve. It has the potential to create false capacity scarcity situations and artificially inflate prices. 

Second, and notwithstanding our comments above, we believe that MISO’s formulation of the X adder is crucial to answering a lot of stakeholder questions regarding how the RBDC Opt Out participation model will affect them. While we understand that the exact formulation of the X adder may be complicated, we were disappointed that MISO did not present this information at the July RASC meeting. 

We also recognize that on slide 11, MISO stated, “MISO is considering a methodology to determine initial X% based on empirical evidence,” and that “Empirical studies could reveal appropriate reliability service that opt-out capacity should provide without adding more complexities.” We also see that on slide 12, MISO states, “MISO will finalize the methodology for future updates on RBDC and X% for opt-out provisions,” and “Market outcomes and reliability needs overtime will determine the methodology for updating the RBDC and X% for opt-out provision.” We merely express our concern that time is running out for MISO to determine this initial X% adder, and that no matter how late in the process MISO figures this out, MISO will need to give stakeholders a meaningful chance to understand this methodology, and MISO should be prepared to reexamine said methodology depending on stakeholder feedback. The viability of the RBDC Opt Out proposal hinges on this methodology. Without more information regarding the formulation of the X adder we aren’t able to adequately consider the merits of the RBDC Opt Out option altogether as too many questions are still outstanding.

That said, we still appreciate some of the added details regarding the proposed structure of the RBDC Opt Out participation model, such as the timeframes for X adder adjustments, the seasonality of the X adder, and the ability of participating LSEs to void their RBDC Opt Out minimum term obligation if and when the X adder increases. 

As another detail, we also look forward to hearing MISO’s response to one stakeholder question concerning how MISO will treat the opportunity to void when the X adder goes up in one season but not in others. 

Draft Tariff Language 

For Draft Module A:

With the addition of the terms, “Initial PRMR” and “Final PRMR,”, we find the use of plain “PRMR” at times a little confusing in draft Module E-1. Furthermore, the way in which “Initial PRMR,” “Final PRMR,” and plain “PRMR” are defined in the draft changes and the existing Module A contemplates three different PRMRs. We wonder if the use of plain “PRMR” without the prior designation of either “Initial” or “Final” now refers to the whole PRMR process (e.g. getting to a requirement), whereas both “Initial PRMR” and “Final PRMR” refer to actual values used in that process. If so, MISO may want to consider adjusting the definition of PRMR in Module A. 

Additionally, the definition of “Final PRMR” suggests that this definition is only the RBDC Adder, and not the sum of the RBDC Adder and Planning Year PRM. We suggest changing the last sentence in this definition to the following (additions in bold, deletions in strikethrough text):

“For LSEs selecting the RBDC Opt Out, Final PRMR is the sum of the applicable Planning Year PRM plus the applicable RBDC Opt Out Adder added to the PRM.

Finally, the definition of “RBDC Opt Out” may be more precise if it more clearly describes what the LSE is opting out of.

For Draft Module E-1:

We have a few questions regarding the modified FRAP provisions covered in Section 69A.9 and elsewhere throughout draft Module E-1:

• For an LSE that elects to FRAP 100 percent of its Initial PRMR, is it still subject to a Final PRMR? If so, by what means may that LSE meet its Final PRMR?
• If an LSE that elects to FRAP 100 percent of its Initial PRMR is indeed subject to a Final PRMR, by what means may that LSE not meet its Final PRMR?
• May an LSE that elected to FRAP 100 percent of its Initial PRMR take advantage of any of its own surplus resources that it bids (or is otherwise eligible to be bid) into the PRA to meet its Final PRMR? If so, how?
• How may an LSE that elects to FRAP 100 percent of its Initial PRMR be subject to a Capacity Deficiency Charge? Conversely, how can such an LSE avoid these charges?

By our reading, it appears that changes to the FRAP under draft Module E-1 will permit LSEs in states that already have robust resource planning processes in place to continue using those processes without the risk of falling short of the PRMR as a whole because of the results of the PRA. However, because of the open questions presented above, we still refrain from stating our support one way or another. 

Other Items

We support MISO’s decision to separate the multi-season block participation model from the reliability based demand curve filing at FERC and we look forward to future developments along that track.

Xcel Energy appreciates the opportunity to provide feedback regarding reliability based demand curves. 

We are concerned that if the LOLE 1 in 10 requirement is not a minimum threshold within each season then there could be seasons that the PRA clears in shortage but the ACP is not high enough to impact future capacity decisions, such as reversing capacity designation for export or delaying retirements.  The North regional curve for the spring appears to be an example of this.

Will MISO provide an updated calculation (following the latest revisions for NetCone and the regional curves) of the seasonal ACPs that would have cleared in PY 23/24 if the RBDC methodology would have been in effect, before the August RASC?

 We have also submitted the Module E-1 Tariff red-lines with our comments, in an email to Stakeholder Relations. 

NextEra thanks MISO staff for seeking input on the Reliability Based Demand Curve (RBDC) proposal. NextEra supports MISO’s pursuit of more efficient capacity market design along with MISO’s decision to bifurcate reforms tailored the demand-side from the supply offer discussions.  The block offer optimization proposal is complex and more time is needed for stakeholders to understand the scope of the uplift implications.

NextEra would like MISO to provide more detail on how the Marginal Reliability Impact (MRI) curves will be developed. The details that have been provided thus far set the foundation for how MISO will slope the MRI curves. But, NextEra would like to better understand how the MRI curves will be adjusted for each year, season, and subregion to achieve the long-run Net CONE equilibrium. We’d like to see a more detailed review of the process, how it accounts for prior-year clearing results, the calculation driving the curve shape based on AFRAP volume, and parameters used in the Monte Carlo analysis.

Minnesota Power RBDC Stakeholder feedback

Minnesota Power appreciates the opportunity to provide stakeholder feedback.  

First, Minnesota Power wants to clarify that the process of having additional presentations and discussions has resulted in a clarified understanding of the proposed RDBC.  The clarification for Minnesota Power helped to alleviate a number of concerns regarding the implementation of the RDBC and the potential impact to the Company and our customers.  Specifically, the option of not opting out when a party has secured adequate capacity for its own expected PRMR and the additional reserves due to the market having cleared at a capacity level higher than the 1 day in 10 loss of load event, that the market exposure for Minnesota Power will be limited to the additional capacity and that will clear at the ACP.  This point is fairly obvious from what has been presented, but the more important realization is that in the event of the market is tight on available capacity, the market would be expected to clear closer to or lower than the 1 day in 10 reliability target, and Minnesota Power would no longer be purchasing capacity above the expected 1 day in 10 PRMR.  

Using a specific example, the PRMR of 1,500 MW and an additional 3% expected capacity for the market clearing would result in Minnesota Power purchasing 45 more MW than what would be required for the current opt out approach (e.g. FRAP).  If the market was too tight to clear at any level of capacity higher than the 1 day in 10, Minnesota Power would no longer be expected to purchase additional capacity above and beyond the 1 day in 10 reliability.  Note that the current opt-out option has been an important resource adequacy tool to demonstrate to regulators that Minnesota Power met the resource adequacy requirements while minimizing market exposure for customers.      Minnesota Power will continue to plan for its system needs including taking into consideration the  PRMR for the 1 day in 10 reliability.  With our State’s robust IRP process and stakeholder interaction, the RBDC does not improve or disagree with our planning.   

Minnesota Power anticipates the short-term market signals provided by the PRA will have minimal impact on our long-term resource decisions, including decisions for development or retiring resources.  The addition of capacity resources can take 3 to 10 years to bring online due to supply chain, interconnection delays, permitting, and regulatory approvals.  The PRA has the potential to provide short-term signals when capacity shortfalls will occur but does not provide the proper signal for longer-term capacity needs.  The Company’s IRP, along with the OMS survey and RRA work, provides more useful information for planning than the RBDC.  Minnesota Power does not believe that the implementation of the RBDC will have material influence on the development or retirement decisions based on the PRA results, and essentially views the claims for providing adequate revenues to deter retirements or development resource to be speculation.  

The proposed methodology seeking to quantify the additional effective reserve margin (called X%) would appear to have a fundamental challenge of needing to quantify the expected amount of capacity that will be expected to be offered in the PRA.  Minnesota Power doesn’t see this as being technically feasible, and the outcome of setting a value of “X” based on the snapshot of historic market clearing simulations does not provide any financial hedge for Minnesota Power to opt out.  

Minnesota Power also believes that the impact of Direct LOL accreditation or some other revision needs to be clearly known and identified how the impact will flow through the RDBC methodology.  One clear area of evaluation is to show the simulated curves based on the DLOL accreditation values in aggregate and determine the impact to the expected clearing price and the additional capacity cleared so the methodology of setting the AFRAP X% is reflective from the corresponding accredited MW values.

In summary, the company does not reject the proposed methodology outright and appreciates MISO’s willingness to provide an opportunity for feed and discussions through the FRAP.  This change is not expected to provide any value to Minnesota Power in reference to resource additions or retirements and has the potential to increase costs to Minnesota Power customers with no improvement to the reliability on the system. 

While not providing an opinion on the need for an RBDC within MISO's RA construct in this set of comments, WEC Energy Group believes the Entergy RBDC opt-out proposal is superior to MISO's.   The Entergy opt-out proposal requires a commitment to demonstrate capacity of something less than 100% of the Initial PRMR while MISO's proposal requires a demonstration of  the applicable Planning Year PRM plus an RBDC Opt-Out Adder for the entirety of its load (and its entire share of LCR for each LRZ).  It is very difficult, if not impossible without substantial excess capacity, for an LSE to select the MISO opt-out because of uncertainty surrounding future  values of Initial PRMRs, the RBDC Opt-Out Adder, capacity accreditation, the timing of its new resources/retirements, and CIL values.  Despite these uncertainties, the MISO opt-out requires a capacity demonstration for each of the next 12 seasons (4 seasons per year for the next 3 years) for 100% of the applicable Initial PRM plus an RBDC Opt-Out Adder for its entire load.  Even if an LSE has 99% of its capacity requirement under the MISO opt-out, it will fail the MISO opt-out provisions, be subject to the Capacity Deficiency Charge, and face possible exclusion from the opt-out program.  In contrast, the Entergy opt-out proposal only requires a capacity demonstration for something less than 100% of the Initial PRMR.  If that amount is 60%, 70% or even 90%, an LSE can, with a certain amount of confidence, select the Entergy opt-out and maintain compliance for the next 12 seasons.  The uncertainty associated with future values impacting an LSE's requirement and accredited capacity are manageable under the Entergy proposal.  The same is not true with MISO's opt-out proposal, rendering it useless unless an LSE has sufficiently long capacity positions (perhaps 120%) for the next 3 years.

WEC Energy Group provides the following comments on the draft RBDC tariff language:

• The tariff language should define when and how the RBDC Opt-Out Adder is established.
• The tariff language should specify whether the RBDC Opt-Out Adder is a seasonal value or an annual value that is applied to all seasons.
• The RBDC opt-out language should refer to the "Initial PRMR for each season" rather than the "applicable Planning Year PRM" to maintain consistency with other tariff language.

MidAmerican appreciates the opportunity to provide feedback on updates to the Reliability Based Demand Curve (RBDC) proposal. (RASC-2019-8) (20230711-12) 

MidAmerican supports a more stable framework to enable long range planning for new and retiring resources. RBDC addresses price stability (in that the prices of the PRA will be less likely to be CONE or very low), but implementation of the RBDC has significantly increased the mid- and long-range uncertainty in terms of the planning reserve MWs that load serving entities need to plan for to ensure they won’t have financial exposure. The RBDC may provide some benefit in terms of delaying some generators from retiring in the short run, but MidAmerican suspects this benefit will be minimal given the fact that most of the unit retirements are due to other factors besides PRA outcomes. In addition, MISO has not provided adequate information regarding long range generation planning certainty with respect to MW of accredited capacity for each resource type, and the seasonal planning reserve margin requirement.

MidAmerican is concerned that MISO is trying to solve problems with long-range resource adequacy by making changes to the planning resource auction (PRA) by introducing the RBDC. With MISO looking to change accreditation processes again, load serving entities are finding it difficult to determine how much capacity they may need in the next planning year, let alone in the long-term timeframe that is needed to add resources. Also, additional concerns include that the demand curve will not be set by the demand and the additional amount of reliability being paid for may have been free because simply clearing or not clearing the auction does not determine if a generator will be available to serve load during tight conditions. In other words, just because a generator does not clear the auction in a season doesn’t mean it won’t be available to serve load for some part of the season. It may not clear because it has a longer planned outage during that season, for example.

With respect to long-range resource adequacy, MISO should focus more on the resource adequacy construct with the objective of making the process more transparent, simple and predictable. The PRA clearing prices provide load serving entities limited information about the future of their generation fleet leaving two glaring issues. The first issue is that the auction clears only two months prior to the start of the planning year which makes it too late for load serving entities to do anything to avoid financial exposure for that year. The generation interconnection queue alone takes several years to get through. The second issue is that there is no ability for load serving entities to predict or project future resource accreditation values for future years to warrant (or not warrant) a retirement or encourage construction of a generation resource of a particular fuel type. Only MISO currently has the hourly load and intermittent resource data separately for each zone and across weather years to assess tight margin hours. MISO should first provide this necessary data to the market but then also develop more simplistic methods of translating this information to a simpler metric such as a planning reserve margin based on seasonal peak load so that load serving entities can make informed decisions regarding long-range resource adequacy.