RASC: Reliability Based Demand Curve (RBDC) Feedback (RASC-2019-8) (20230118)

WEC Energy Group continues to believe that MISO’s Advanced FRAP (AFRAP) proposal does not provide LSEs with a viable opt-out of the Reliability Based Demand Curve (RBDC).  The AFRAP proposal requires an LSE to obtain RERRA approval and make a 3-year commitment to demonstrate 100% of an LSE’s obligation for every season of the upcoming planning year (without incurring a Capacity Deficiency Charge penalty).  In order for an LSE to select the AFRAP alternative, the LSE must have 3-year forward certainty regarding each season’s PRM (12 values), the seasonal accreditation for each of its resources, its load forecast, the exact commercial operation date of its new resources, and other RA construct changes that may occur.  For most LSEs, this certainty is not achievable which renders AFRAP unusable.  Even if LSEs know with certainty the 3-year forward seasonal PRMs (which they do not), the risk associated with year-to-year and season-to-season variability in SAC accreditation (and proposed changes to wind and solar accreditation) is enough to not allow use of AFRAP by most LSEs.

RBDC FEEDBACK ON BEHALF OF THE STAFF OF THE LOUISIANA COMMISSION AND THE MISSISSIPPI COMMISSION (“STATE COMMISSIONS”)

 1. The State Commissions adopt and re-urge the RBDC comments submitted to the RASC by the LPSC Staff that were posted on 1/3/23. MISO still has offered no analysis or support for the claimed benefits of the RBDC and the RBDC curve design that is being explored. There is no support for the proposition that the RBDC will incent new capacity and/or delay the retirements of existing capacity.

 2.  The State Commissions do not support the use of Net Cone in the design of the demand curve.  There has been no demonstration that Net Cone should be used to set the Auction Clearing Price or that it would properly reflect customer valuations of any changes in expected unserved energy. 

3.   The AFRAP option does not provide the opt-out needed to protect ratepayers from adverse cost impacts of the proposed RBDC design. It does not, nor does the existing FRAP, allow avoidance of the load requirement increase.  Combined with the impacts that appear to be associated with the SAC proposal, this additional load requirement will have enormous cost consequences on many customers, with no demonstrated benefits.

4.   While we recognize the sense of urgency felt by MISO and the IMM to adopt the proposed RBDC, in light of the many fundamental questions posed by the States regarding the proposal that neither MISO or the IMM have yet satisfactorily answered, and the still unresolved issues associated with non-thermal resource accreditation, the State Commissions strongly urge MISO to allow more time for discussion and analysis in the evaluation of the RBDC proposal.

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:

• Regarding the AFRAP Requirements, are there contingency plans for an event if the utility loses some of its elected AFRAP capacity for an extended period of time?

Net CONE Methodology:

• In the previous feedback request regarding Reliability-Based Demand Curves, AMP asked how the term of three years was determined for historical data. MISO responded that three years’ worth of data is sufficient to reflect going-forward costs, that the objective of Net-CONE is to approximately represent the average going forward cost of capacity, and that one of the events should not drive Net-CONE value dramatically to avoid large year-in-and-out variations but also include steady system changes. AMP would still like additional detail on evidence supporting MISO’s response. For example, we believe more (greater than three) years and data points would provide a less volatile / more stable Net-CONE value.
• In MISO's response to feedback on Reliability-Based Demand Curves, posted 1/17/23, MISO stated that a forward-looking Net Cone had been considered, but data accuracy and data availability challenges limit MISO's ability to accurately determine forward-looking Net-CONE without making unnecessary assumptions. Can MISO elaborate on the specific data accuracy and availability challenges? Also, can MISO elaborate on what is meant by unnecessary assumptions? Any model, forward or backward looking, requires making assumptions.
• Why is MISO proposing a methodology that is LRZ specific for CONE but for inframarginal rents it is by footprint?

Marginal Reliability Impact (MRI) Curves:

• Additional detail is needed regarding Demand Response resources. Will Demand Resources be treated as a supply resource and captured as part of the supply stack?

General Comments:

• In MISO's response to feedback on Reliability-Based Demand Curves, posted 1/17/23, MISO stated it is working with a consultant for analysis and simulation purposes. Is MISO working with Brattle? If not, what consultant is MISO working with?
• In MISO's response to feedback on Reliability-Based Demand Curves, posted 1/17/23, MISO stated that MISO intends to assess periodically capacity market performance with RBDC curves. More specificity around this process needs to be developed and documented (for example, review frequency and member involvement).

The premise of the RDBC is to use the clearing price to provide an indication the tightness of the capacity supply.   There are direct means of assessing the tightness using a load and capability reporting mechanism.  Price is an indirect method of assessing the tightness of the capacity supply, but is deemed as being preferred based on the academic discussions on the intersection of supply and demand curves.  The bottom line, is that it won't provide a useful pricing mechanism to incentivize resource development, given the fact that we have a one year capacity market.  There are existing state regulatory planning mechanisms including Integrated Resource Planning and other load and capacity reporting. 

The most significant concern that Minnesota Power has on the RDBC is that the process  does not allow clarity on the planning reserve margin due to the nature of the supply and demand curve intersection.  The AFRAP is not a satisfactory resolve because it only provides a fixed value for a defined period of time.  Acknowledging that the current process doesn't guarantee the PRM dur to changes in the LOLE modeling results, the variation of the PRMR due to the RDBC creates uncertainty in the long-term planning process that doesn't add value.

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 January 18^th RASC meeting; we look forward to future discussions and workshops on this topic. During MISO’s RBDC presentation, MISO introduced the ‘Annual Commitment Model’ concept which provides a participation mechanism for resources seeking longer term price certainty through a single annual PRA offer that MISO then adjusts to a seasonal ‘per MW Day’ price based on a resource’s SAC MW in a given season. MISO emphasized that a critical aspect of the annual commitment model is the concept that a resource with an annual offer that clears for a single season, also clears for the entire planning year. In addition, MISO’s RBDC presentation states that both “Seasonal and annual offers can set the ACP.” Vistra requests that MISO provide examples of scenarios where a resource with an annual offer that clears for a single season also clears for the entire planning year, even when that resource’s per MW Day price in a season is higher the ACP. Specifically, Vistra would like to better understand how MISO plans to position a resource in the seasonal supply stack when that resource has a per MW day price that’s above the ACP in two or three seasons of a planning year. MISO also noted during the RASC meeting that modifications to uplift provisions may be needed in order to make resources with annual offers whole, if the “cleared capacity or seasonal ACPs are not sufficient to cover the total annual offer.” Additional details on possible modifications would be helpful, along with examples of scenarios where a resource’s annual offer setting the ACP in one or more seasons.

Finally, Vistra agrees with MISO that the Marginal Reliability Impact Curves (MRI) “should reflect the incremental reliability value to consumers of additional capacity.” Given the MISO region’s resource adequacy challenges and shrinking thermal fleet, it’s critical that the MRI curves and values developed for individual LRZs reflect each incremental unit of capacity’s marginal contribution to improving system reliability, including attracting new capacity resources and incentivizing incumbent resources to stay online as the MISO region continues to tighten. The presence of a high proportion of state-regulated vertically integrated utilities does not change the fundamental role of the capacity market to accurately value resource adequacy.  Vertically integrated utilities will be largely insulated from the cost of capacity under a reliability-based demand curve.  To the extent any load serving entity (competitive or regulated) is net short capacity, the appropriate price signal for that load serving entity is based on net cost of new entry. Using a lower cost basis will lead to under-investment and exacerbate the reliability concerns already present in the MISO market.

Draft RASC Comments by the Environmental Sector

Reliability Based Demand Curve

MISO Dashboard ID#: RASC20198

February 1, 2023

Annual Commitment Model and Seasonal Co-optimization (slides 5-10)

We greatly appreciate that MISO provided an example for how seasonal co-optimization may work in conjunction with the option for annual commitment. The practice of providing examples is one we support and hope to see more of.

Although the example provided on slide 9 captures what is likely to be the most common case, it leaves a lot of questions for what will happen in less common, but still frequent, scenarios. This was discussed in some detail during the January 18th meeting, thus we will not elaborate further beyond asking MISO to provide examples for the below situations (each representing a change from the example provided). Additionally, we stick to the use of a fixed seasonal requirement for simplicity's sake as used in the original MISO-provided example.

• In the example provided, R1 submitted the same exact offer for each season.
• How would co-optimization differ for R1 if it provided only an annual offer instead of four equal seasonal offers?
• Are there any advantages or disadvantages for or from offering seasonal or annual offers in such a case as when the offer is consistent throughout the year?

• In the example provided, R3 was the least cost resource ($10.3 per MW/Day) and thus cleared the market in each season.
• What would occur if R3 clears the markets in some seasons but not others?
• Using the example provided, what would occur in the Fall if the seasonal requirement was only 13 MW but R3’s offer price was set at $21?
• If an annual offer clears the market in some seasons but not others, how might that affect that resource’s same annual offer’s function in the seasons in which it does clear?
• If an annual offer clears the market in some seasons but not others, how might that affect the seasonal or annual offers of other resources for the same season or year?
• If a resource provides an annual offer but does not clear each of the seasons, must it still operate for all seasons of the year? If so, would that risk other resources with a lower-priced seasonal offer from being able to clear for each respective season?

The last sub-bullet above is in part a reference to the final bullet on slide 10, which states that there may be a “need to modify current uplift provisions to make annual offer resources whole if the resultant cleared capacity or seasonal ACPs are not sufficient to cover the total annual offer,” and that “Only under certain conditions uplift provisions are needed and the expected MWP volume is low.”  Please provide more clarity with respect to MISO’s thinking in this regard.

Finally, as a point of clarification for future utilization of the type of chart used on slide 9, it would be helpful if annual offers were also listed in the $ per MW/day format as used for the two resources showing seasonal offers. In the example provided by MISO, this would mean that R3’s offer price on the table would read as “$60,000 ($10.3 per MW/Day),” or similar. There was some confusion during the meeting caused by this discrepancy even though the explanation was provided on the bullets to the right.

Marginal Reliability Impact Curves (slides 11-14)

MISO proposes to use marginal reliability impact as the basis for determining the shape of its RBDC.  While this may end up being an appropriate choice, MISO should also consider other objectives in the design of its curve, including its tendency to send stable (or at least not volatile) price signals, its susceptibility to market power abuse, and its overall likelihood of meeting the PRMR consistently.  The MRI-based curve should be evaluated on this wider range of factors, which are regularly considered by other RTOs (e.g. PJM) in the development of demand curves, to determine whether the curve will serve the purpose that MISO and its stakeholders intend.

As MISO moves toward presenting simulation results to stakeholders on the expected outcomes of the proposed sloped demand curve in terms of reliability performance and cost, it must also provide a counterfactual with the performance of the existing vertical demand curve, for stakeholders to be able to understand how the proposed curve performs compared to the current situation.

Additionally, in the November 30st RASC MISO presented its plan to use the shape obtained for the marginal reliability curve with the Value of Lost Load, to support the recovery of Net CONE. We ask MISO to further explain the use of Value of Lost Load and how it supports the recovery of Net CONE.  Also, we ask MISO to clarify any interactions and impact on the design and implementation of the sloped demand curve for the PRA resulting from the ongoing work on scarcity pricing being developed in the Markets Subcommittee, including the work planned to update the Value of Lost Load and on the review of the Operational Demand Reserve Curve.

Net CONE (slides 15-19)

MISO proposes to use a net cost of new entry (Net CONE) approach to anchor the RBDC.  We agree that this is the most common means of determining an administrative cost of new entry among RTOs/ISOs with centralized capacity markets.  However, we note that the calculation of administrative Net CONE presents many contentious issues for MISO and its stakeholders to address and should not be rushed, especially as the initial development of this methodology will set the stage for many years to come.  We also note that an administrative estimate of the cost of new entry is less accurate than an empirical determination would be.  For example, at the inception of PJM’s capacity market, it was envisioned that an empirical Net CONE value would eventually be used once the market clearing prices over a period of years had begun to reveal the true net cost of new entry.  We urge MISO to rely on administrative estimates of Net CONE for only a short period of time, until more accurate empirical figures are available.  We also ask MISO to clarify at the next RASC its perspective on the role of administrative and empirical estimates of Net CONE.

Looking again to PJM as an example, administrative Net CONE there has frequently exceeded the clearing prices (i.e., the actual cost at which developers are willing to build or maintain capacity) by a factor of two or more. In part, this overestimate resulted from PJM retaining a combustion turbine (CT) as its reference resource for determining Net CONE, despite the fact that few if any CTs were being built.  Instead, developers were choosing to build more efficient combined cycle resources that had higher upfront costs but greater expected energy revenues over their asset life, and thus a significantly lower Net CONE.  Slide 16 indicates that MISO plans to use an “advanced CT” to calculate the Net CONE value, which could lead to significantly overstated Net CONE (as historically seen in PJM) and thus excessive procurement of capacity at higher prices than is reasonable for consumers to pay.  The Environmental Sector urges MISO to undertake a transparent and robust comparison of the available technologies for calculating Net CONE. What is the rationale and set of criteria MISO is using to justify the use of an advanced combustion turbine as its reference technology?  In fact, PJM is moving away from CT.  It has recently filed (Docket No. ER22-2984) at FERC with the intention to switch to the combined cycle as its reference resource because its Net CONE value can be calculated with greater accuracy than that of a CT, and because its Net CONE value will result in a curve that better meets the region’s reliability requirement without procuring excess capacity. 

MISO also indicates its intent to use historical data to calculate the inframarginal rent figure used in Net CONE determination.  The Environmental Sector urges MISO to evaluate and present to stakeholders the alternative of a forward-looking calculation of inframarginal rents.  Historical data is a poor proxy for suppliers’ forward expectations of energy and ancillary service market revenues, which will be strongly affected by expected gas prices as well as changes to energy and ancillary service market design that MISO is developing (as noted in its October filing in AD21-10).  We refer MISO to the Brattle Group’s most recent Net CONE report^[1] produced as part of PJM’s Quadrennial Review for a full explanation of the importance of a forward-looking offset for calculating Net CONE.

Advanced Fixed Resource Adequacy Plan (slides 20-24)

MISO proposes to introduce an additional participation alternative under the RBDC paradigm, which it calls the Alternative Fixed Resource Adequacy Plan (AFRAP).  On its face, the introduction of the AFRAP appears to have been necessitated because a change to an RBDC paradigm will eliminate the certainty that LSEs had with FRAP when paired with a vertical demand curve. Thus, the chief difference between the AFRAP and the existing FRAP appears to be that the AFRAP would provide LSEs with certainty in the amount of capacity they must procure, whereas LSEs utilizing the FRAP would now be required to procure an amount of capacity equivalent to what the auction would have cleared for their load had that LSE sought to purchase capacity through the auction.  For example, if the PRA with an RBDC clears an amount of capacity greater than the PRMR, LSEs using the FRAP would be accountable for also purchasing extra capacity to match the reserve margin that the PRA cleared.  This new uncertainty can be problematic because an LSE might face the need to procure additional capacity if the auction clears capacity in excess of the PRMR.  In exchange for this certainty, LSEs would be required to opt into the AFRAP for a three-year period, rather than a single planning year, and would also forgo the ability to satisfy only part of their obligation through self-supply. 

The Environmental Sector seeks further explanation from MISO about the trade-offs implicit in MISO’s proposal of the AFRAP.  Quantity certainty is a critical factor in LSEs’ ability to prudently plan to meet their PRMR, but MISO proposes to offer such certainty only to LSEs who agree to be bound by their election of the AFRAP for three years and to procure 100% of their capacity needs through the AFRAP.  Implicit in the AFRAP proposal is that the three year term and limited flexibility to procure less than 100% are somehow necessary to mitigate unstated harms caused by providing the LSE with quantity certainty.  Yet MISO has not articulated any specific reason why this would be so.  If the auction clears an excess of capacity, this does not change the fact that an LSE that has procured the exact PRMR for its FRAP has met MISO’s standards for resource adequacy.  A higher cleared quantity in the auction is not an indicator of what is needed for reliability, but instead an indication that the region has a surplus of affordable capacity–hardly a reason to make an LSE that has elected the FRAP retroactively procure additional capacity. Conversely, if the PRA were to clear short, it would be detrimental to reliability to permit LSEs with FRAPs to release some of their capacity so as to match the reserve margin that the PRA cleared. 

Absent a robust explanation from MISO as to why LSEs must forgo flexibility in exchange for quantity certainty, it appears that MISO may be proposing the AFRAP in order to achieve a separate objective – reducing the extent to which utilities rely on the PRA. 

We also ask that MISO more fully consider the effect its RBDC proposal, including its effects on FRAP and the proposed AFRAP, may have on states’ abilities to meet their respective decarbonization goals. As one example, Minnesota appears likely to pass a 100 percent decarbonization by 2040 goal, and the decisions MISO makes on the structure and use of the sloped demand curve will have a magnified effect on Minnesota’s ability to reach its goals should this new bill become law. While it is impossible to to predict what other states will do in the future, it is unlikely Minnesota is the last state within MISO’s footprint to pursue this type of decarbonization legislation. In MISO’s attempt to fulfill its obligation to be policy neutral towards states, it must also consider how its decisions affect the ability of those states to craft their own energy policies while remaining reliable. This is not to say that MISO should lower its reliability standards–rather, we ask that MISO review how else it can meet its reliability goals while providing more flexibility for LSEs and the states that regulate them.

Next Steps and timeline (slides 25-26)

Considering the importance and long term ramifications of this issue, we encourage MISO to adjust the stated timeline as necessary if stakeholder feedback provides sufficient cause for a closer examination of its current plans. However, we do not want this issue to slip longer than necessary, thus we also propose that MISO consider more frequent, but less lengthy meetings.

The number and complexity of subjects currently being considered before RASC demand a lot of time and energy from stakeholders in order to have efficient and productive meetings. However, because there is so much to cover and prepare for, it is difficult for stakeholders to prepare for these meetings as thoroughly as they might otherwise do. With less time for preparation, stakeholders come into the meetings with either more questions, less understanding, or both, all of which add to the already long duration of these meetings. For these reasons, we request that MISO consider breaking up RASC meetings further so that they meet more often but for shorter timeframes. We believe that this would serve everyone’s interest, result in less frustration, and help MISO and stakeholders more quickly come to a resolution regarding the matters before RASC at this time. It should also help MISO stick to its stated timeline.

Respectfully submitted,

The Environmental Sector

DTE appreciates the ability to provide feedback on the reliability-based demand curve proposal. DTE remains fully in support of pursuing a reliability-based demand curve in an effort to more appropriately price incremental capacity. However, DTE supports feedback provided both through written stakeholder comments and verbal feedback at the January 18^th RASC that MISO must make substantial changes to the proposed AFRAP methodology in order to provide a reasonable and realistic opt-out provision. MISO’s proposed methodology (3-year requirement, 100% obligation, capacity deficiency charge upon failure to meet obligation) and the inherent financial risk it introduces would eliminate the AFRAP as a realistic option to demonstrate adherence to capacity requirements, especially with the increased capacity accreditation volatility associated with MISO’s transition to SAC methodology. Requiring an entity to commit to 100% of seasonal capacity obligations for three years lest it is charged a higher penalty than any auction result is unreasonable. DTE encourages MISO to explore other potential methodologies, such as a partial AFRAP or other ways to mitigate potential risk.

Feedback by Public Service Commission of Wisconsin (PSC) Office of Regional Markets (ORM) Staff to Midcontinent Independent System Operator (MISO) on the Reliability-Based Demand Curve (RBDC) proposal. 

1. Could MISO please adjust their RBDC proposal to offer an option in which utilities can FRAP or AFRAP at their 1-in-10-based PRMR without securing additional capacity? We provide further clarity on why the current FRAP and AFRAP options are problematic for a state like Wisconsin that has a 1-in-10 requirement for utilities: 

• If the PRA is designed to clear at 1-in-10 on average, that means in in some years the PRA will clear below 1-in-10. Consequently, utilities in states with a 1-in-10 requirement would be out of compliance with their state if they relied completely on the PRA. Alternatively, if those utilities were to FRAP at their PRMR to meet their state’s 1-in-10 obligation and make up the rest on the PRA, under MISO’s current proposal, they would end up securing capacity above 1-in-10 on average over the years as the lowest amount of capacity they would ever secure would be at 1-in-10, while utilities in states without such a state-level requirement that relied on the PRA would average a lower capacity obligation: at 1-in-10. 
• The AFRAP proposal is potentially problematic for the same reason, in addition to the fact that because the AFRAP option locks utilities in for three years at a time, it could reduce their ability to adjust to rapidly changing accreditation and PRA policies at MISO (assuming MISO would not lock utilities that select to AFRAP into whatever PRA and accreditation policies were in place during the first year that they entered the AFRAP).  
• Alternatively, if the PRA under the RBDC clears at far greater quantities than the 1-in-10-based PRMR, this is problematic for regulated states and it could undermine state decisions regarding the level of reliability that is worth funding. We note that the IMM previously stated his expectation was that the PRA would clear on average at 1-in-10, but MISO has not shared any reports or data that demonstrate potential clearing quantities or prices. 

2. Can MISO please provide stakeholders with more detail on the AFRAP proposal? We asked several questions in the last round of feedback about the AFRAP and MISO did not address them. 

• Is it possible that if supply was short for multiple years in a row, using the PRA clearing quantities to set the AFRAP target would exacerbate a shortage as utilities that AFRAP would be required by MISO to secure less capacity when the footprint needs more?  
• Why is it preferable to use previous PRA data to set the AFRAP obligation, rather than finding a way for the AFRAP obligation to reflect the current needs of the system? What alternatives did MISO consider? 
• Please clarify the need for and quantity of MW that utilities would be prevented from selling under the AFRAP option. Are there any alternatives for these MW that would allow them to continue to contribute to resource adequacy in MISO? 
• Please provide information to justify the 3-year commitment for the AFRAP. Why is this necessary under the RBDC, but not a vertical curve? 

3. Can MISO please provide stakeholders with a report showing different options for the RBDC shape? We note that in PJM, stakeholders were presented with a report detailing multiple MRI curve options. It would be beneficial for MISO stakeholders to understand the alternatives that MISO considered. We also note that PJM’s consultant recommended not using the MRI curve in PJM at this time, and we would appreciate knowing whether MISO has considered pitfalls of an MRI curve and benefits of alternatives, and how MISO determined that an MRI curve was the best option.  

4. We encourage MISO to invest more fully in the stakeholder process on this issue by:  

• Responding to all individual stakeholder feedback in writing, as MISO only provided a short and incomplete response to stakeholders’ December feedback 
• Providing reports that detail the methods, assumptions, and data that MISO has used thus far to make determinations about the RBDC design - stakeholders need this information to make their own assessments and they need assurance that MISO is doing its due diligence on this proposal 
• Attending to points of disagreement with stakeholders by having more discussions and by fully investigating stakeholder suggestions and contemplating the merits and pitfalls of such alternatives against MISO’s proposal 
• Sharing an FAQ document similar to the document MISO shared related to the Seasonal Construct last year 
• Holding a public Q&A session with MISO and the IMM for interested stakeholders  

WPPI reiterates the comments we made last month on this item.  (https://www.misoenergy.org/stakeholder-engagement/stakeholder-feedback/2022/rasc-reliability-based-demand-curve-proposal-and-design-elements-rasc-2019-8-20221130/)

In addition, we do not understand the process described at slide 14, and request that MISO provide further explanation of how the ‘translation’ would occur:

“Translation of MRI curves into RBDC curves through Monte Carlo analysis to support recovery of Net CONE (annualized) through capacity revenues”

AMP, MEC, MPPA, and SLEMCO support WPPI's feedback.

MEC, MPPA, and SLEMCO support AMP's feedback.

AMP, MEC, and MPPA (and maybe other LSE Coalition members had time permitted) also submit the following questions for MISO's response with explanation so that stakeholders can better understand MISO's proposals:

Annual Commitment Model

• What offer parameters would the PRA supplier control? 
• Would the supplier control the specific or maximum amount that could be cleared per season? 
• Would the supplier control the price or range of prices that MISO would use in the PRA clearing process?
• What are the necessary and sufficient conditions for a rational supplier to choose to use the annual offer rather than seasonal offers?
• When any rational supplier incurs one or more input costs in annual terms, must that supplier then receive continuous daily revenue streams over that same annual term in order to be profitable?
• What are the necessary and sufficient conditions for creating an annual offer type to create overall (including make-whole payments) aggregate PRA cost savings?
• Does MISO think possessing some degree of market power in one or more season is necessary for an annual offer to clear where seasonal offers couldn’t? 
• In clearing annual offers, will MISO leverage the supplier’s market power in one season to use a supracompetitive effective seasonal offer price for that season so that MISO can use a lower effective seasonal offer price for seasons in which there is relatively more supply, more suppliers, different binding PRA clearing constraints, or less demand?
• What seasonal cost level would MISO use to prevent applying below-cost seasonal pricing (i.e., uneconomic in the seasonal terms that MISO has otherwise forced the capacity construct into) when clearing an annual offer? 
• Would MISO let the IMM determine that seasonal cost reference level? 
• Is that a moot question because the annual offer is solely intended to entice suppliers to offer in the PRA when they otherwise would receive PRA offer mitigation exclusions from the IMM?
• If it’s not a moot question for that reason, then
• Could any market power mitigation rules or processes hinder MISO’s objective(s) here? 
• What would be the IMM’s role in the treatment of annual offers in the PRA clearing process?
• What would be the IMM’s role in the determination of make-whole payments for cleared annual offers?

RBDC

• In the Monte Carlo modeling, to what extent will MISO assume changes in inframarginal energy and operating reserve (EOR) revenue affect shifts in modeled PRA supply?
• Does the PRA demand curve represent the aggregate Planning Reserve demand of LSEs in the MISO region?
• If not, should it?
• Should the PRA design be consistent with and facilitate the resource planning processes and preferences of LSEs in the MISO region?
• Should the PRA demand curve be defined by a Planning Resource (or ZRC) product that comports with those LSE resource planning processes and preferences?
• Should the Planning Resource (or ZRC) product reflect LSEs’ resource planning objective to serve their respective gross loads as forecasted within some reasonably bounded range?
• Should the PRA demand curve reflect preferences of LSEs and their respective RERRAs in the region to mitigate steep scarcity pricing and to mitigate clearing quantity risk beyond some target reliability level of Planning Reserves (e.g., 0.1 LOLE)?  That is, should the PRA demand curve should be bounded in terms of price under scarcity conditions and bounded in terms of quantity under surplus conditions relative to the target MW amount?
• Will MISO update RBDC parameters on some regular schedule, or according to any particular internal process or stakeholder process? 

Net CONE

• Has MISO considered using a composite prototype resource (e.g., 70% thermal generator/30% battery storage) on which to base the CONE and the inframarginal EOR revenue for netting?
• How will MISO model or calculate inframarginal EOR revenues?
• How often would MISO update Net CONE values?

I'm happy to discuss.

David Sapper

dsapper@ces-ltd.com

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

Formulation of Demand Curve

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. Specifically, MISO should provide detail on the inputs and methodology for how the Marginal Reliability Impact curves are translated into Reliability Based Demand Curves through Monte Carlo Analysis to support recovery of Net CONE. The EOCs would also like to know how this proposed methodology compares with other RTOs/ISOs that utilize a sloping demand curve in a capacity auction.  

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. An LSE that has procured enough generation to meet the large majority of its customers’ needs at the 0.1 LOLE reliability standard should not be forced to pay extra PRA costs caused by a sloped demand curve.  As presently designed, AFRAP is not a plausible or attractive option because of the combination of the following four provisions; (1) an LSE must cover 100% of their PRMR, (2) the planning reserve margin (PRM) is uncertain across the three year term, (3) the penalty for not meeting the AFRAP obligation is set at the capacity deficiency charge (2.7 x CONE) which is significantly higher than the highest possible auction clearing price, and (4) an LSEs ability to sell excess capacity is limited. The effect of all these provisions is that AFRAP contains a similar or only slightly lower level of uncertainty as compared to participating in the PRA -- but imposes much higher price risk while also limiting an LSE’s ability to sell excess capacity. Taken as a whole, MISO’s AFRAP proposal is not a reasonable or feasible option for LSEs to utilize.  That is, it is not a reasonable alternative method for meeting an LSE’s capacity obligations with the adoption of the proposed sloped demand curve.  The omission of a reasonable AFRAP option renders the current sloped demand curve proposal not just and reasonable.

The EOCs believe that the following three changes should be made to MISO’s AFRAP proposal so that AFRAP becomes a reasonable and meaningful option and is able to meet desired objectives:

1. Under AFRAP an LSE should only have to cover 90% of their PRMR as opposed to the 100% requirement proposed by MISO. This would ensure that LSEs using AFRAP will continue to self-supply the large majority of their PRMR while still having the ability to use the PRA as a balancing market to buy/sell relatively small deficit/surplus capacity positions.
2. The 3-year AFRAP term should use the PRM that corresponds with the 0.1 LOLE reliability standard so that LSEs have an option to avoid the PRMR uncertainty imposed by the sloped demand curve.
3. Remove the limitation on LSEs’ ability to sell excess capacity to the market. MISO’s stated mission is to enable reliable delivery of low-cost energy. Prohibiting available capacity from participating in the MISO market will lower system reliability and uneconomically raise prices which is contrary to MISO’s mission.

As a general matter, the EOCs believe that the adoption of a sloped demand curve and AFRAP does not change the primary purpose of the PRA, which is to serve as a balancing market for LSEs to resolve relatively small surplus/deficit positions. Even with MISO’s proposed changes to implement a sloped demand curve, the PRA cannot, and reasonably should not, serve as a primary source of capacity for LSEs to meet their PRMR obligation.