In the January 6 meeting of the Resource Adequacy Subcommittee (RASC), stakeholders were invited to send feedback on MISO's proposed Resource Availability and Need (RAN) sub-annual resource adequacy construct changes. In your response, please group feedback into the following categories:
Comments are due by January 20, 2021.
THERE IS ADDITIONAL FEEDBACK PERTAINING TO THIS REQUEST AVAILABLE WITH RASC FEBRUARY 3 MATERIALS.
Clean Grid Alliance Comments to the Resource Adequacy Subcommittee (RASC)
re: MISO’s Proposed Forward Capacity Requirement
Clean Grid Alliance (CGA) appreciates the opportunity to provide this feedback to the MISO Resource Adequacy Subcommittee (RASC). At the September 9, 2020 meeting of the RASC, MISO proposed implementing a forward capacity demonstration requirement which would supplement the existing MISO Planning Resource Auction (PRA). Under this forward capacity demonstration requirement, all Load Serving Entities (LSEs) would be required to demonstrate to MISO in advance of the PRA that they either own or have contracted for a large portion (MISO proposed at least 50%) of the future capacity obligation for their load. MISO indicated that the reason it was advancing a forward capacity requirement demonstration is a concern that some LSEs have placed a high reliance on the PRA to purchase capacity and this could potentially lead to a reliability issue. MISO also suggested that resources used to meet this requirement should be within the LSEs zone, and that there could be a penalty for not meeting the requirement. At that meeting, Entergy, advocating for a forward capacity requirement, asserted that absent a specific forward capacity requirement, LSEs benefit from “free ridership” on the capacity that is built by others. Clean Grid Alliance provides the following comments in response to this issue and MISO’s proposal.
Summary:
Detailed Comments:
Additionally, the PRA fails to provide a price discovery value that meets or exceeds that which is lost through the elimination of bilateral trading opportunities. The PRAs provide price discovery once a year whereas the bilateral trades provide for continuous price discovery. The price discovery available through the PRA is limited to one delivery year, which compares negatively to the flexibility of longer period price discovery that is available through a robust bilateral market.
o The location-specific approach of the PRA encourages resources to take part in the zones where they provide the most benefit.
o A forward demonstration of capacity occurs through the MISO-OMS Survey.[2]
• A similar market construct has already been litigated at the FERC. FERC previously rejected a MISO proposal to bifurcate the capacity market to address a potential capacity deficiency in the MISO footprint. In an effort to ensure future resource adequacy needs are met in retail choice areas, MISO proposed adding a forward-looking capacity market to the existing PRA construct in 2017. The FERC rejected the proposal on the grounds that MISO did not sufficiently demonstrate that a bifurcated market would result in an efficient and desirable outcome, i.e., an economic outcome.[3]MISO’s forward capacity requirement proposal at the RASC (and certain participants’ comments) is another “bite” at the same apple.
• There is no legitimate reason to discourage transactions through the PRA market. Neither MISO nor its RASC participants have demonstrated that the current resource adequacy construct is insufficient for attracting and retaining enough capacity to meet reliability needs, including MISO’s 1-in-10 loss of load expectation.
• MISO and some stakeholders have overstated the reliance on the PRA. While some LSEs certainly rely on the PRA as one tool to meet their capacity requirements, LSEs have historically utilized, and continue to utilize, forward bilateral contracts to meet MISO’s resource adequacy requirements. A forward procurement mechanism would undermine the existing mechanisms used to meet resource adequacy requirements. Municipal aggregators, as well as competitive retail suppliers that offer locked-in rates to their customers, already have incentives to enter into bilateral contracts for capacity in order to hedge PRA capacity prices. The existing capacity market construct allows LSEs to flexibly craft hedges, self-supply arrangements, and bilateral contracts to meet their specific needs and appetite for risk. It also gives those LSEs the ability to fine-tune their arrangements closer to the coming, year to address changing conditions and load forecasts.
The following table summarizes PRA statistics for 2018-2019, 2019-2020, and 2020-2021.
2018/2019 2019/2020 2020/2021
Fixed Resource 34.8% 34.4% 34.1%
Adequacy Plan
Self-Supply 59.8% 61.0% 60.5%
Total Before Spot 94.6% 95.4% 94.6%
Market Reliance
Spot Market 5.4% 4.6% 5.4%
Reliance
MISO has not demonstrated that a forward capacity demonstration requirement would lessen this already small reliance on the PRA (depending on the forward procurement target). This table is further evidence that MISO has not shown that there is an issue with a lack of forward capacity procurement.
• To the extent that the forward procurement mechanism would include a locational component to the capacity demonstration requirements, the mechanism would potentially create market power concerns that would be difficult to mitigate because large portions of generation are owned by a single entity in many locations in MISO. Not only would this raise costs for a portion of MISO customers, clearly a negative impact, but it would also allow vertically integrated utilities to stifle retail competition. Hence, it would likely undermine competition at both the wholesale and retail level.
• Low capacity clearing prices in MISO appropriately reflect the amount of installed capacity in the region. Low capacity clearing prices do not reflect a flaw in market fundamentals, rather, prices have been appropriately low and reflect the level of installed capacity in the region. To the extent there is an issue of free ridership, which has not been established, free ridership only exists when the market is long on capacity and prices are low. To the extent the market shortens, and prices increase, LSEs would pay something close to the cost of a new generating unit, thereby eliminating any “free ridership issue.” As noted by MISO’s Independent Market Monitor, Potomac Economics, it is inefficient and counterproductive to attempt to solve a pricing problem by imposing new administrative burdens, restrictions, and requirements on market activity. Rather, if pricing is in fact the problem, MISO should seek solutions that would address the pricing problem itself.
• This proposal is not necessarily congruent with current state regulatory policies regarding resource adequacy capacity requirements. State regulators maintain other mechanisms and procedures to ensure their respective jurisdictional utilities procure power on behalf of customers in a cost-effective way. States have the sole authority to determine their utilities’ resource investments and forward planning. The OMS Survey assists states and MISO in knowing what resources are available and planned for the future, and states and their utilities can thus “true up” supply as needed through contracts or new resource construction to meet their needs into the future.
• This proposal would add administrative cost and complexity, and without a showing that a problem exists and that the proposed change would address that problem, the added complexity and burden on MISO staff is unwarranted and would ultimately raise costs for consumers.
It is in the public interest for MISO LSE’s to share resources across the footprint, and this is one of the key intents of a robust regional market. For the reasons detailed above, CGA urges MISO to drop the proposed forward capacity demonstration requirement from its Sub-annual Capacity Construct proposal.
Xcel Energy appreciates the opportunity to provide feedback on MISO's Resource Adequacy Sub-Annual Construct proposal, provided below by category:
The Entergy Operating Companies (EOCs) appreciate MISO’s efforts in developing an initial sub-annual construct proposal. The EOCs are eager to see the LRZ specific data that MISO plans to release later this month, which will show how this construct proposal will impact each LRZ’s supply requirements and accredited capacity position. Upon reviewing this data and other analyses, the EOCs will be better informed to provide additional feedback on MISO’s initial sub-annual construct proposal.
In addition to the general comments above, please review the attachment provided for our continued response regarding the Planning Resource Auction (PRA), including minimum capacity requirement for PRA.
Consumers energy appreciates the opportunity to provide feedback on MISO’s initial Sub-Annual Resource Adequacy Construct Proposal. Our comments are centered around several of the construct’s components, namely the “Seasonal Construct Reflecting Sub-Annual Needs” Design, the accreditation of resources being based on Available Capacity (ACAP) versus Unforced Capacity (UCAP) which is used currently, and the Minimum Local Forward Capacity Demonstration.
Seasonal Construct Reflecting Sub-Annual Needs Design
A “seasonal construct reflecting sub-annual needs” design is a good first step in weaning the MISO Planning Resource Auction (PRA) off of its current annual construct and toward a sub-annual, or seasonal, construct which is necessary given the changing make-up of the footprint-wide generation fleet. However, this design needs to go at least one step farther. Since asset owners participating in the PRA will not have complete information regarding the actual quarterly availability of their resources (assuming a 4-season design) at the time of the one annual auction, a series of true-up auctions should be added. The frequency of these auctions would correspond to the number of sub-annual periods so, for example, a 4-season design would have 4-quarterly true-up auctions. This concept is also one that will be familiar to MISO market participants as it is, essentially, a residual auction. The current MISO PRA construct is also a residual auction. The idea behind the true-up auctions is that as asset owners garner additional information about the actual availability of their resources as the season in question comes closer to the present, they will better know whether they need to acquire or divest of capacity resources. This will result in a more efficient market and in better resource adequacy as both surplus and deficient players will have a clearinghouse available to them in which to sell or obtain capacity resources based on the latest available operational information.
Available Capacity (ACAP)
While Consumers Energy is unequivocally in favor of mechanisms that improve resource adequacy, we have several concerns regarding the ACAP proposal.
First, the proposal seeks to include all units that are offline during tight constraint conditions into the determination of capacity accreditation. This appears to include units that could have been online if instructed to be so by MISO. Specifically, units offered as economic with startup times greater than 2 hours, and units on planned and, in some cases, maintenance outages and derates would realize reduced accreditation under this proposal. Under the MISO resource adequacy construct, it is inappropriate to include planned outages for capacity accreditation and, in some circumstances, it is inappropriate to include maintenance outages as well. Planned outages are scheduled at least months, and often years, in advance of the actual outage which offers MISO plenty of time to appropriately schedule them such that they do not cause or occur during tight constraint conditions. In the case of maintenance outages, recent tariff amendments allow maintenance outages to occur with 14 days-notice so long as they do not fall during times of tight conditions. Maintenance outages that occur with less than 14 days-notice are treated as forced and do, therefore, impact the asset’s accreditation via MISO’s existing accreditation methodologies. Units offered to the MISO market as economic with startup time greater than 2 hours simply need a Day-Ahead signal to be online. Reducing capacity accreditation for these units would cause further distortions in the energy markets because it would incent offers of must-run for facilities with startups greater than 2 hours. This would suppress the energy prices by putting uneconomic energy into the market and would require these generator owners to seek recovery of these costs outside the market. Ultimately, accrediting capacity in this way enables MISO to be inaccurate in forecasting need and pushes the cost of that inaccuracy not to the market as a whole (which is most appropriate) but to the individual generator owners who relied on MISO to approve outages responsibly and commit generators accurately.
Second, and as alluded to above, MISO’s tariff already addresses both maintenance and planned outages via a minimum 4-month notice period in the case of the former and a 14-day notice period in the case of the latter. Both of these requirements are the result of recent tariff changes developed and agreed to by MISO and stakeholders via the Resource Availability and Need (RAN) initiative and obviate the need for the additional changes proposed by the IMM and subsequently adopted by MISO. These amendments have been in place for just over one year and need to be allowed to permeate through the MISO market so that their effects have time to be felt. In this light, the IMM’s proposal is premature.
Third, other initiatives are underway through the stakeholder process that will also enhance resource adequacy. For example, the Multi-Day Operating Margin Forecast (see Integrated Roadmap items MSC008 – Multi-Day Operating Margin Forecast and IR085 – Exploration of a Forward Market Mechanism in the Issue Tracking Tool of the MISO website) states that “a multi-day volumetric forecast can better identify potential operating days issues in advance”. Already implemented through this effort are improvements to the Multi-day Operating Margin Forecast Report such that it now includes outage and forecast uncertainty information. As noted above, these efforts need to be afforded time to work. Thoughtful and measured approaches such as this, designed to improve resource adequacy, are already addressing concerns expressed by the IMM and subsequently adopted by MISO.
In conclusion, MISO and stakeholder initiatives, both recently implemented and forthcoming, address resource adequacy measurements and requirements in a thoughtful and measured approach. The IMM’s proposal is both premature (in that recent changes to MISO’s resource adequacy construct have not been afforded enough time to work) and redundant given the impending tariff amendments.
Minimum Local Forward Capacity Demonstration
A minimum local forward capacity demonstration is a necessary and important component of the new PRA from both a resource adequacy and a cost-causation standpoint. However, similar to our comments above regarding the seasonal construct reflecting sub-annual needs, the proposal as presented needs to go at least one step farther. MISO is proposing a capacity demonstration of 50% meaning that, prior to the PRA, Load Serving Entities (LSEs) would be expected to procure at least 50% of their Planning Resource Margin Requirement (PRMR) for the prompt PRA year. These resources must also be local (i.e. located within the Local Resource Zone (LRZ)) to ensure that the LCR requirement is met. The aforementioned “one step further” is that the 50% threshold needs to be much higher for at least two reasons. First, resource adequacy may be compromised if only half of the current year’s capacity is actually procured (i.e. real). The system needs, and customers expect, power to be available when they need it. Leaving half of a current year’s capacity requirement to chance is a risk that customers do not want to take. The state of Michigan recently, and quite successfully, implemented a capacity demonstration of 95% which ensures resource adequacy for its citizens. Second, the majority of the customers in the MISO footprint are served by either transmission-dependent or transmission-owning (i.e. vertically integrated) utilities. These utilities already procure the overwhelming majority of their capacity needs via state-regulated constructs such as Integrated Resource Plans (IRPs). As a result, most of the large providers of capacity will already have far in excess of 50% of their requirements. Furthermore, in the absence of a capacity demonstration, those LSEs who do not fall into the previously mentioned utility classifications are actually incented NOT to procure their capacity needs. Historically, capacity prices in the MISO PRA have been very cheap, reflecting the fact that MISO utilities procure most of their capacity resources ahead of the auction. Non-utility LSEs take advantage of this prudent utility practice by buying cheap auction capacity. Essentially, this is a problem of cross-subsidization. Bundled utility customers are paying for the resource adequacy burden that should be borne by non-bundled utility customers. By requiring a capacity demonstration, non-bundled utility customers would finally be paying for their fair share of the footprint’s resource adequacy requirements.
Consumers Energy once again thanks MISO for the opportunity to provide feedback on this very important topic.
WEC Energy Group provides the following feedback on MISO’s Resource Adequacy (RA) proposal presented at the January 2021 RASC meeting.
Capacity Accreditation:
MISO proposes to accredit resources seasonally based on the resource’s availability (ACAP) during the tightest operating conditions, including planned outages. WEC Energy Group believes that the combination of the RAN Phase 1 Outage Coordination requirements coupled with the enhancements to the Maintenance Margin, MOM forecast and scarcity and emergency pricing mechanisms provide sufficient incentives to avoid maintenance during tight conditions. We continue to support the use of UCAP for the accreditation of resources.
As stakeholders noted during the January RASC meeting, more detail and examples are required in order to understand how ACAP interacts with the Planning Reserve Margin (PRM), which is calculated with an LOLE study that models planned outages. Planned outages within the LOLE model increase the PRM. A resource that has a planned outage during tight conditions will reduce ACAP of the resource. It seems that we are possibly accounting for the planned outage twice, once in the PRM and again in the ACAP. Additional examples, with the associated math, are needed to demonstrate that double-counting of planned outages is not occurring. We also seek additional examples on the ACAP (or UCAP) weighting of resources with long start-up times and the proposed definition of “tight margin” hours.
We are concerned that the use of ACAP will unnecessarily penalize resources for their past planned outage behavior rather than their future availability. For example, a resource with an 18-month maintenance schedule might not have been available in the spring of 2020 but it will be available during the spring of 2021. The ACAP proposal provides no mechanism to account for this type of planned maintenance.
WEC Energy Group supports a mechanism for resource owners to forecast their planned outages without risk of ACAP reduction if completed well in advance of a particular season. We also note that resources with scheduled full or partial outages for a majority of the season (such as any 60 days of the 90 days in a season) should not qualify as capacity for that season without the risk of ACAP reduction. This will provide resource owners with flexibility to manage their long lead-time planned outages without ACAP risk due to unforeseen circumstances.
Seasonal Requirements:
As WEC noted during the January RASC meeting, the addition or removal of resources to drive the LOLE to 0.1 days/year and the subsequently seasonal distribution of that LOLE is highly dependent on the type and characteristics of those resources. The RASC needs to review the current methodology and determine whether that approach is appropriate under a seasonal construct. The RASC also needs to review the implications of assigning a LOLE of 0.01 days/year to those seasons that have no distribution of the annual LOLE. Assigning a LOLE of 0.01 days/year to obtain a solution from the model for a season with no risk should not reduce the LOLE of the seasons with risk. For example, if the summer season is assigned 0.08 days/year and the winter season is assigned 0.02 days/year, the spring and fall seasonal LOLE assumed to get the model to solve should not reduce the summer and winter LOLE risk.
Minimum Capacity Requirement for the PRA:
WEC Energy Group appreciates the concern of potential reliability issues associated with LSEs that rely on the PRA to obtain a large percentage of their Planning Reserve Margin Requirement (PRMR). However, we do not believe MISO should address this issue through a tariff requirement to establish a minimum capacity requirement for the PRA. Rather, it is the responsibility of the Relevant Electric Retail Regulatory Authorities (RERRA) to establish resource adequacy requirements for LSEs within their jurisdictions, not MISO. RERRAs and LSEs are responsible for reliable and cost-effective electric service for their end-use customers and should make their own decisions regarding forward capacity procurement and reliance on the capacity residuals within the PRA.
The OMS Resources Work Group (OMS RWG) provides the following comments on MISO’s January 6th update on the Resource Adequacy side of its RAN initiative. This feedback does not represent a position of the OMS Board of Directors.
Seasonal Resource Adequacy Requirements
Subject to more information as it becomes available, the OMS RWG is generally supportive of a four-season Resource Adequacy construct. We look forward to reviewing the sub-annual construct results when they are released later this month.
Availability-based accreditation
Now that we have established that the future resource adequacy construct will have two or four seasons, the OMS RWG agrees that it is the right time to discuss resource accreditation. The OMS RWG supports changing accreditation to more greatly value resources that offer availability and flexibility during the tightest hours of need, but there is still much uncertainty with MISO’s Available Capacity (ACAP) proposal. As such, the OMS RWG requests that MISO provide more detailed information on its ACAP proposal, highlight any differences from the IMM’s ACAP proposal, and explain why it chose to deviate from the IMM’s proposal for accreditation. Stakeholders having a deeper understanding of the proposal is important so that we can identify outstanding issues and avoid any unintended and avoidable consequences from shifting to ACAP for accreditation
In the view of the OMS RWG, a four-season RA construct is a must if MISO wishes to pursue ACAP for resource accreditation. Outages during tight hours in one season should not impact a resource’s capacity accreditation in another season, and we request that MISO confirm this will be true in their proposal for ACAP (e.g. An outage during a tight hour in the fall of the previous year would not impact the accreditation of that resource for future summer seasons).
One question the OMS RWG has on the ACAP proposal: how does MISO plan to account historic performance of ACAP using resource data from years prior to implementing ACAP? It is a fair assumption that resources will be utilized differently under a seasonal Resource Adequacy construct than they are under the current construct. A shift to from using UCAP to ACAP for accreditation will also cause a change in behavior, as under current accreditation practices, there are no consequences for taking certain types of outages, even during periods with tight reserve margins. While there will likely be a minimal difference between ACAP and UCAP during a summer season (which the current construct targets as important), the other seasons could be significantly impacted from using pre-ACAP historic data. Resource performance during pre-ACAP, pre-seasonal construct years might not be indicative of how those resources will perform in a seasonal construct with ACAP used for accreditation.
Some form of transition period might be needed to accommodate the shift in capacity accreditation.
Planning Resource Auction, including minimum capacity requirement for the PRA
The OMS RWG was split on the minimum capacity requirement for the PRA, with some commission staff members supporting the proposal and others opposing it. If MISO decides to move forward with this proposal, it is essential that the language used not encroach on state jurisdiction over Resource Adequacy and resource planning.
Several questions from the OMS RWG include:
- Would firm service with a resource located outside of the LRZ allow for that resource to qualify for the 50% requirement?
- What level of penalty would MISO impose on LSEs that fail to procure a sufficient level of capacity prior to entering the PRA, when there is sufficient capacity to meet the needs of the LSE in the PRA (both locally and regionally)?
- Some LRZs have an LCR that is approximately 50% of its PRMR. If a LRZ were to have an LCR below 50% of its PRMR, would the 50% threshold be lowered, or would LSEs with that LRZ be required to procure more resources locally beyond the LCR level?
- What other solutions were considered to alleviate the problem this proposal attempts to address? (increased Planning Resource Auction (PRA) price cap to the level of capacity deficiency charge)
- Why has this proposal been added to the RAN initiative? Would MISO be willing to file this proposal in a separate docket at FERC?
ITC Comments Concerning the Proposed Minimum Capacity Requirement for PRA
We appreciate the significant efforts MISO has made towards reforming the PRA so that it better supports resource adequacy as the industry accelerates it shift towards renewable energy. We have agreed with the general direction MISO is taking in moving to a seasonal construct with improved accreditation standards and more realistic modeling in its LOLE study.
MISO's initial proposal for reform, however, includes a specific provision we do not agree with. As described in MISO's recent RASC presentation, it is proposing a 50% local capacity requirement demonstrations for all LRZs.
This provision artificially limits ratepayers' ability to benefit from access to low-cost capacity. Further, it provides no additional reliability benefits beyond what already exists in our current regulatory construct.
Generation planning currently occurs at the state level between LSEs and their regulators. If some kind of local requirement is determined to be needed via that process, then it will be granted without the need for RTO approval. Formalizing a Tariff provision requiring all LRZs to maintain a particular local requirement likely infringes on states' regulatory jurisdiction and does not provide any reliability value while doing so.
Given this, we strongly recommend MISO remove the provision prior to FERC filing. We also look forward to continued progress with MISO and stakeholders on the broader set of PRA reforms.
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),
Alcoa Power Generating Inc. (APGI)
And
NIPSCO Large Customer Group (NLCG)[1]
Regarding
RASC: RAN Resource Adequacy Construct Changes and Forward Capacity Requirement Demonstration (RASC010, RASC011, RASC012)
January 20, 2021
ABATE, IIEC, LEUG, MIC, TIEC, CMTC and APGI, as representatives of the End-Use Customer (EUC) Sector, and NLCG appreciate this opportunity to provide comments to MISO.
Background
During the January 6, 2021 meeting of the MISO Resource Adequacy Subcommittee (RASC), MISO advanced for consideration and discussion its initial proposal for a sub-annual resource adequacy construct that includes several elements. The most significant components of MISO’s proposal include: (i) the establishment of seasonal resource adequacy requirements: (ii) a simultaneous capacity auction with distinct seasonal components; (iii) the use of available thermal generation capacity during defined resource adequacy hours to establish the capacity accreditation for such generation resources; and (iv) the imposition of a forward capacity demonstration requirement upon all Load Serving Entities (LSEs). This forward capacity demonstration requirement would supplement the existing MISO Planning Resource Auction (PRA).
Under the proposed forward capacity demonstration requirement, LSEs would be required to demonstrate to MISO in advance of the PRA that they either own or have contracted for 50% of their capacity obligation (Planning Resource Margin Requirement) for their load. Moreover, under MISO’s proposal, this forward capacity demonstration requirement must be met entirely from resources that are sited within the LSE’s Local Resource Zone (LRZ). MISO is considering the possibility of implementing a penalty mechanism for not meeting this proposed forward capacity requirement.
MISO asked for feedback on its proposed resource adequacy construct revisions, including the proposed forward capacity demonstration requirement.
ABATE/IIEC/LEUG/TIEC/CMTC/MIC/APGI/NLCG Comments
We appreciate the opportunity to comment on the proposal MISO put forth for consideration.
Our comments at this stage focus on the proposed forward capacity demonstration requirement for LSEs. We continue to review the other aspects of MISO’s resource adequacy proposal, and we may have concerns with or comments on those other aspects once we complete our review and/or after MISO provides further detail on those aspects of its proposal.
We do not support MISO’s proposal to impose a local forward capacity demonstration requirement on LSEs outside of the PRA. In prior RASC meetings, MISO raised the possibility of introducing such a requirement. In our September 23, 2020 written comments to MISO on this topic, we expressed our concern that MISO has not demonstrated the need to add a forward capacity demonstration requirement to supplement the MISO PRA.[2] In the intervening period since we filed our comments in September 2020, MISO has not presented any new evidence to demonstrate the need for such a requirement. In particular, it has not presented evidence that its current resource adequacy construct is unlikely to attract and retain sufficient capacity to meet MISO’s one day in ten year loss of load expectation standard in the long term absent the addition of a forward capacity demonstration requirement. Nor has MISO shown that a significant capacity shortfall is imminent within MISO without the addition of a forward capacity demonstration requirement to supplement the PRA. Moreover, MISO has not demonstrated that individual LSEs are excessively relying on the PRA for their capacity requirements to an extent that threatens system reliability or that inappropriately shifts costs to other market participants. Therefore, MISO has not presented a demonstrable need for a forward capacity requirement.
During the January 6, 2021 RASC meeting, MISO presented a specific proposal for a forward capacity demonstration requirement that would require LSEs to procure 50% of their capacity obligation outside of the PRA and would further require that this capacity obligation be met entirely from local resources that are situated within the LRZ. The proposal to specifically set the forward capacity obligation at 50% (as opposed to another percentage or amount) has not been justified by any analysis or evidence. Therefore, the proposal appears to be arbitrary and does not have analytical support. Moreover, the proposal is unreasonable in that it would apply the same 50% forward capacity demonstration requirement on a local basis to all LSEs serving load in all LRZs, irrespective of differences in the magnitude of the Local Clearing Requirement (LCR) across LRZs. The proposal to impose a uniform 50% forward capacity demonstration requirement on all LSEs in all LRZs fails to recognize significant differences in the size of the various LRZs, nor does it recognize differences in generation market concentration across LRZs. Therefore, this component of MISO’s proposal is also arbitrary and is not supported by reasoned analysis.
In addition to our concern that MISO’s proposed forward capacity requirement is arbitrary and is not supported by adequate analysis, the proposed requirement would create other problems that we discussed in our September 23, 2020 comments. Specifically, under MISO’s proposal, instead of the current, single PRA capacity requirement that can be met through any combination of resource investments, forward bilateral contracts or PRA purchases, there would be two separate capacity requirements – one, a new requirement that must be met in advance of PRA, and one that does not have to be met until the time of the PRA. Moreover, the requirement that must be met in advance of the PRA would have to be met entirely from resources situated with the relevant LRZ.
We believe that MISO’s proposal to require that the forward capacity demonstration requirement must be fulfilled entirely using local resources will create serious market power problems and significantly increase capacity costs to loads, particularly in LRZs where generation ownership is highly concentrated, such as Lower Michigan, Lower Illinois and Louisiana/Texas.
Unlike the PRA, the forward bilateral capacity market is not subject to active market power monitoring and mitigation by the MISO Independent Market Monitor (IMM). Indeed, the IMM explicitly stated during the January 6, 2021 RASC meeting that it does not support MISO’s forward capacity demonstration proposal because the IMM does not have the visibility that it would need into the bilateral capacity market to protect against the exercise of market power.
MISO’s proposed forward capacity demonstration requirement would break the capacity market into two and make the portion of an LSE’s total capacity requirement that is subject to the forward capacity demonstration, captive to the bilateral forward capacity market within each LRZ. As a result, that part of the LSE’s total capacity requirement that is procured outside of the PRA would no longer be protected from local market power exploitation, because the PRA would no longer be able to discipline the market price for that portion of the LSE’s total capacity requirement. As noted above, this concern would be particularly acute in those LRZs where there is a high control and/or ownership concentration in the market for local capacity.
MISO’s proposal would effectively allow owners of resources in LRZs with a high concentration of generation ownership to leverage their local market power by inflating the cost of capacity through bilateral capacity contracts with LSEs, who would be obligated to meet this requirement entirely from local resources. It is important to note that this market power concern would not be resolved by limiting those resource owners, with significant local market power, to making bilateral capacity sales based on rates that are set at a price that is no greater than their sunk fixed costs. For many generation owners, these sunk fixed costs are well in excess of the net Cost of New Entry (CONE) price. Furthermore, even if such costs are not in excess of CONE, or those bilateral rates were capped at the net CONE price, the situation would still be problematic, as the avoided fixed O&M costs and avoided incremental capital costs for continued operation of most existing generation are well below the net CONE price. In LRZs where the ownership and/or control of capacity resources is highly concentrated, those owners would potentially have the ability under MISO’s proposal to drive up their bilateral sales price to the highest price they are allowed to sell at especially if their ownership or control of capacity is such that they are a pivotal supplier. The MISO PRA has strong reference level and conduct threshold provisions to protect against this type of market abuse. The bilateral market does not have these protections except to the degree that buyers can choose to buy from the PRA rather than bilaterally. Therefore, the imposition of cost-based rates on generation owners by the FERC is not likely to limit the ability of these owners to significantly inflate the cost of meeting MISO’s proposed local forward capacity demonstration requirement through the exercise of local market power.
Our September 23, 2020 comments explained that splitting the MISO capacity market into two, as proposed by MISO through its forward capacity demonstration requirement, would introduce multiple problems, including the creation of barriers to demand response participation and interference with retail and wholesale customer choice in areas where those are allowed. We will not repeat these concerns here, but we instead refer MISO to our September 23, 2020 comments for a full discussion of our concerns in these areas.
In addition, the imposition of a local forward capacity demonstration requirement that must be met entirely from resources that are situated in the applicable LRZ ignores the fact that some LSEs rely on resources located outside of the local LRZ to meet the capacity needs of their loads. For example, Entergy has testified that it relies on capacity from units of the Union Power Station in Arkansas (located in LRZ 8), to meet the capacity needs of Entergy Louisiana, LLC (located in LRZ 9), pursuant to an agreement that was approved by the Louisiana Public Service Commission in November 2015.[3] MISO’s proposal to require LSEs to meet 50% of their capacity requirement using resources that are located within the same LRZ as the relevant load would unnecessarily complicate efforts by LSEs to rely on resources located outside of the local LRZ to meet their resource adequacy requirements.
Furthermore, MISO’s proposal would result in a transition from its current resource adequacy paradigm to a structure that imposes LRZ-specific, local forward resource adequacy requirements on individual LSEs outside of the PRA, without establishing a competitive market with independent oversight to meet such local resource adequacy requirements. This proposed approach goes against MISO’s governing principles. For example, the Statement of Guiding Principles for the MISO System Planning Process states that one of MISO’s guiding principles is “to enable a competitive electricity market to benefit all customers.”[4] MISO’s proposal to impose local resource adequacy requirements on LSEs outside of the PRA, without ensuring the availability of a competitive market outside of the PRA with independent oversight to meet these requirements, runs contrary to these guiding principles.
As we noted in our September 23, 2020 comments on this topic, the problems discussed above are similar in nature to the problems that plagued MISO’s failed Competitive Retail Solution (CRS) proposal that was ultimately outright rejected by FERC in Docket No. ER17-284-000. We urge MISO to abandon the proposed forward capacity demonstration requirement to avoid the prospect of expending significant MISO and stakeholder resources on the proposal, only to see it rejected by the FERC in the same manner that the FERC rejected the CRS proposal.
Thank you again for giving us an opportunity to provide these comments. If you have any questions concerning our comments, please do not hesitate to contact:
Jim Dauphinais
Brubaker & Associates, Inc.
(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)
(636) 898-6725
Ali Al-Jabir
Brubaker & Associates, Inc.
(Consultants to ABATE, IIEC, LEUG, NLCG and TIEC)
(361) 994-1767
Kevin Murray
McNees Wallace & Nurick LLC (for CMTC)
(614) 719-2844
Kavita Maini
KM Energy Consulting, LLC (Consultants to MIC)
(262) 646-3981
Steve Dowell
Alcoa Power Generating Inc.
(812) 842-3377
[2] Our September 23, 2020 comments to the RASC on this topic can be viewed by clicking the following link:
[3] Louisiana Public Service Commission, Docket No. U-33510, In Re, Application of Entergy Gulf States, Louisiana, LLC for Approval to Purchase Power Blocks 3 and 4 of the Union Power Station and Request for Timely Treatment and Cost Recovery, Supplemental Testimony of Anthony P. Waltz on Behalf of Entergy Gulf States Louisiana, LLC, July 2015, page 2, line 6 through page 4, line 12.
Louisiana Public Service Commission, Docket No. U-33510, In Re, Application of Entergy Gulf States, Louisiana, LLC for Approval to Purchase Power Blocks 3 and 4 of the Union Power Station and Request for Timely Treatment and Cost Recovery, Order No. U-33510, November 5, 2015.
[4] Board of Directors, MISO Independent System Operator, Inc., Statement of Guiding Principles for the MISO System Planning Process, March 2016.
[1] ABATE, IIEC, LEUG, TIEC, CMTC, MIC and APGI are all MISO Members in the End-Use Customer Sector. NLCG is a non-MISO Member stakeholder whose members include large end-use customers within Indiana that are interruptible and/or have cogeneration facilities and that take service under NIPSCO Rate Schedule 831, which allows limited market purchases through Northern Indiana Public Service Company (NIPSCO).
General comments on the proposal
Alliant Energy waits for MISO to provide additional clarity on issues such as actual seasonal reserve margin requirements, seasonal accreditation amounts by resource type (ie. seasonal ELCC for both wind and solar resources), and performance of existing MISO portfolio under such conditions. It is critical that MISO understands magnitude of portfolio impacts and transition time needed to meet compliance with requirements. It is also critical for MPs to understand their projected requirements and capabilities (capacity positions) under the proposal. We believe MISO should accommodate ample transition time.
Additionally, we are concerned that the accreditation and PRM calculations using “tightest operating conditions” does not provide certainty for LSEs in long-term resource planning (load and capability projections). It seems that the types of hours could vary from year to year, resulting in uncertain PRM and accredited capacity levels. This would particularly impact intermittent resources such as wind and solar. E.g. are the tight hours day/night which would impact solar significantly? Are the tight hours typical wind / light wind conditions?
Seasonal resource adequacy requirements
Seasonal requirements via calculations during tight hours appears unstable. Summer peak tight capacity hours are unique in that such tight hours are tied to conditions such as temperature and humidity build-out. MISO has not demonstrated the predictability of tight hours for other seasons: How are tight hours determined or identified, and what are they tied to? Low wind? Lack of solar support?
MISO has not clarified how transmission import/export limits vary with season, which seems a key component for flexibility.
Availability-based accreditation, including the proposed UCAP/ACAP conversion ratio methodology
Alliant Energy is concerned that availability-based ACAP ratings are not adequately stable for resource planning purposes. Resource outages are a necessary part of maintaining reliability and unforeseen outages cannot necessarily be avoided. Further, seasonal accreditation via calculations during tight hours also appears unstable. Summer peak tight capacity hours are unique in that such tight hours are tied to conditions such as temperature and humidity build-up. MISO has not demonstrated the predictability of tight hours for other seasons: How are tight hours determined or identified, and what are they tied to? Low wind? Lack of solar support?
Planning Resource Auction (PRA), including minimum capacity requirement for PRA
Alliant Energy is supportive of a concept such as a 50% minimum local forward capacity demonstration for the prompt Planning Year. We share concerns about potential “free riders” who rely on the residual capacity auction. Understandably, this issue deserves additional stakeholder discussion.
Day Ahead performance obligation, including treatment of resources with sub-annual operation
Alliant Energy supports must-offer requirements that apply only to the specific seasons that the resource clears. However, we are concerned that the IMM may not accept such flexibility for resources that do not clear. The seasonal construct needs to accommodate portfolio flexibility in addition to provide confidence of 24/7 reliability.
MidAmerican Energy Company appreciates this opportunity to comment on MISO’s proposed resource adequacy construct.
Seasonal Resource Adequacy requirements
MISO says it will “calculate PRM/LRR requirements on a seasonal basis using 2-4 sub-annual PRMs/LRRs with optimal planned outage scheduling, while monitoring impacts from accreditation changes and refining planned outage method.”
MidAmerican comment
MidAmerican generally agrees with a four-season construct permitting Market Participants to shut down uneconomic resources seasonally.
At Slide 16, MISO indicates it will “perform separate LOLE analysis to meet respective seasonal LOLE risk targets” to “meet the LOLE standard of 0.1 days/year.” While MidAmerican generally agrees with the approach, we’re not sure how best to translate the annual “0.1 day/year” standard into a seasonal measure. It seems that Market Participants will have different overall capacity requirements depending on whether the LOLE study allows, say, 0.1 day/year in the summer period and 0.0 risk in other seasons; or 0.05 day/year in the summer and winter periods but 0.0 risk in the spring and fall; or 0.025 day/year in each season; etc. Ideally the reliability criteria would be set to minimize overall capacity requirements, but we’re not sure if MISO has contemplated this. On a related note, it would seem that ACAP should be defined by the tightest hours of the year rather than the tightest hours of each season.
Resource Accreditation; Independent Market Monitor’s accreditation proposal
MISO says it will “accredit by season based on resource's availability (ACAP) during the tightest operating conditions including planned outages and utilize a UCAP/ACAP conversion ratio to align PRM and accreditation.”
MidAmerican comment
MidAmerican believes the Available CAPacity (ACAP) approach has merit in addressing forced and planned outages and resource lead-times. MidAmerican is concerned that the proposal, as we currently understand it, would penalize resources based on luck rather than operating characteristics and may inappropriately impact the pooled benefits that current exist under the MISO construct.
A significant portion of MISO’s value proposition derives from the capacity benefits of pooled risk, and while we believe the IMM’s proposal is worth developing further, it must not harm the existing value of shared risk.
The accreditation proposal appears to undermine this concept of pooled risk in some areas. For example, the proposal appears to penalize a resource that happens to be on a planned outage during an emergency, even if that outage had been scheduled with MISO’s blessing at a time of low apparent risk. A similarly-situated resource that scheduled a similar-duration planned outage at a similar time of year would not be penalized if that outage didn’t happen to coincide with an emergency. Thus the differing accreditations of these two resources would not be based on differences in the performance of the resources, but rather on the random, unforeseeable timing of emergencies. If indeed MidAmerican’s understanding is correct, then this seems to conflict with the concept of pooled risk – the principle that the impacts of random risks should be shared rather than assigned to specific parties.
Among other things:
Planning Resource Auction
MISO says it will “conduct independent auctions for all seasons at one time to meet seasonal PRM/LCR requirements and is proposing a minimum local forward capacity demonstration.”
MidAmerican comment
MidAmerican generally agrees with this approach.
On a related note, MISO altered its tariff several years ago to prevent resources from clearing the auction if they were unlikely to be available for extended portions of the summer. While MidAmerican doesn’t have specific suggestions, we realize this is an issue with a seasonal construct: should resources be permitted to clear in a season if they will be on planned outage for much of the season? If not, how can any resource ever take an extended planned outage for a major overhaul? MISO’s recent tariff change was intended to avoid 1) extended planned outages during peak periods, and 2) planned outages that effectively lasted for an entire Planning Year. Market Participants could address those restrictions by scheduling outages of reasonable length during off-peak periods. It’s not clear how those provisions would best translate into a seasonal construct.
Minimum capacity requirement
MISO would require load‑serving entities to “procure prior to the auction at least 50% of their PRMR.”
MidAmerican comment
MidAmerican supports any provision that would align cost and causation with respect to each load‑serving entity’s contribution to the Local Clearing Requirement (LCR) within a zone. Under the current tariff, an LSE can own adequate generation to supply all of its Planning Reserve Margin Requirement in advance, with the great majority coming from within its own Local Resource Zone – yet prices within the LRZ can be driven to CONE if other entities do not supply a reasonable portion of their PRMR from within the LRZ, thereby causing the LCR to bind. It seems to us that LSEs should supply not only their appropriate PRMR, but also an appropriate portion of the PRMR from within the LRZ, where it can reliably serve the LRZ’s load.
MISO’s proposal appears to be one means to help address this issue, but there are likely other means that would also work.
Day-Ahead Performance Obligation
MISO says PRA cleared resources will “have must offer obligations for the seasons for which they are cleared except for outages [including forced and planned outages, or de-rates reported in the CROW] reported in the CROW during those seasons.”
MidAmerican comment
MidAmerican agrees that resources that clear the PRA should retain a must‑offer obligation. MISO should clarify that if a resource does not clear the PRA, then that resource does not retain a must‑offer obligation; to do otherwise would not permit Market Participants to consider seasonal operation of resources.
Market power mitigation
MidAmerican believes the tariff’s current provisions for market monitoring would have to be altered to acknowledge a seasonal construct. At first blush, it appears this might be addressed by allowing Market Participants to seasonally offer into the seasonal auction at no less than the cost of keeping the resource in operation for that season. Resources that did not clear the seasonal auction would not have to remain in service, and resources that cleared would be assured of receiving enough auction revenue to offset their costs.
MISO's proposed seasonal resource adequacy construct raises market power concerns that have not been recognized or addressed by MISO Staff. Without addressing these concerns we do not recommend proceeding with the proposed changes.
Energy Michigan submits the feedback in the attached file, and requests that document be appended to this feedback and inserted in the feedback file.
Our complete and detailed feedback is in the attached. We see that the Sub-Annual Reliability Construct has merit if it makes planning for RA fit better with the actual operation of resources for RA. We are addressing three main outstanding issues:
A. Competitive Perspective
B. Mandatory Participation in Auction
C. No Local Minimum Capacity Requirement
Again, the attached document contains our full feedback and should be included with our feedback comments herein.
for Energy Michigan,
Alex Zakem
DTE appreciates this opportunity to provide feedback on MISO’s initial proposal for a seasonal resource adequacy construct. While there is still more analysis to do, which may further inform our understanding of MISO's proposal, DTE will share some initial thoughts and reactions.
Seasonal Resource Adequacy Requirements
DTE is generally supportive of a four-season construct. Such an approach would balance providing a more granular representation of the shifting resource portfolio in each season and allow for seasonal operation of conventional resources while minimizing some of the additional effort such as that needed to establish monthly reliability requirements. With respect to the seasonal resource adequacy requirements, DTE seeks additional clarification on certain aspects of MISO’s proposal:
Availability-based accreditation, including the proposed UCAP/ACAP conversion ratio
While DTE understands the critical importance of resource availability, we have some concerns around MISO’s proposal for availability-based accreditation, which are described in more detail below:
If MISO does continue with a resource adequacy hours-based approach for accreditation, then all resources should be evaluated based on the same set of tight margin hours. This would include wind and solar resources.
Planning Resource Auction (PRA), including minimum capacity requirements for PRA
DTE supports capacity planning constructs that drive all market participants in the footprint closer to the behaviors that are assumed in MISO’s resource adequacy construct, namely the long-term regulated resource plans that utilities develop through state processes. Along these lines, DTE supports a capacity construct which includes meaningful requirements for capacity demonstration, including local requirements. While a 50% requirement is an improvement over the current state, DTE would support an even higher requirement based on the local clearing requirement in each zone.
DTE is also interested in better understanding how the annual auction with multiple seasons could support flexibility in outage planning and other changes in capacity position. One of the features of a summer-focused construct like the current one is that generation fleets have more flexibility in scheduling outages in shoulder seasons. For example, if a planned outage is scheduled for the spring, but must be delayed to the fall, the current annual construct imposes few restrictions on resource owners that would prevent such an adjustment. However, the annual construct with multiple seasons could conceivably lock-in a resource owner’s outage commitments. DTE is interested in understanding what flexibility would be available to shift outages between seasons after the annual auction, such as mid-year true-ups in capacity position or other measures. This is an especially important design element that we believe MISO has not yet fully addressed.
If the construct is to facilitate seasonal outages, the design of the seasons will be critical. Since summer reliability risks can transpire from May to September, MISO will need to be thoughtful about how it determines the time periods that fall within each season to simultaneously allow flexibility for resources while ensuring maximum availability during high summer loads. MISO should also look to align the FTR seasons with the PRA seasons to allow market participants to more efficiently hedge their congestion risk.
Day Ahead performance obligation, including treatment of resources with sub-annual operation
MISO stated that resources will have the flexibility to participate in the season(s) of their choice. DTE is interested in better understanding some of the practical implications this raises:
WPPI’s primary goal is that any resource adequacy construct establishes capacity requirements that provide for resource adequacy at the agreed upon level (and no more). The construct should maintain relatively stable requirements and an appropriate allocation of risk at a sub-annual level (along with capacity accreditation that is consistent with its contribution to resource adequacy). Finally, the construct should provide flexibility for generators to take outages when projected market energy prices are not expected to cover their fuel and other relevant operating costs.
Regarding MISO’s proposal to include a Forward Capacity Requirement, WPPI thinks that this should not be included in the seasonal construct discussion. Moreover, the adoption and design of any forward requirement should be left to the discretion of state regulators for the Load Serving Entities under their purview.
For the specific feedback items, WPPI provides the following more-detailed feedback of MISO proposed sub-annual resource adequacy construct changes, grouped into the categories specified by MISO.
A key element of MISO proposed sub-annual resource construct is ensuring risk is appropriately allocated when establishing resource adequacy requirements. WPPI requests MISO discuss with stakeholders how the LOLE analysis will allocate LOLE risk across seasons, including identification of periods with little to no risk.
WPPI understands that the discussion of allocating risk across seasons is in the early stages and there will be more discussion; however, it was mentioned at the last RASC meeting that for seasons that do not have LOLE risk identified, a default 0.001 LOLE risk target may be applied. This is concerning because by artificially requiring such a high LOLE requirement for these seasons may unnecessarily increase the cost of ensuring resource adequacy. WPPI requests that MISO explain to stakeholders how it proposes to prevent this outcome.
Lastly, along with MISO’s proposal of a seasonal construct of “2-4” seasons, MISO proposes a must-offer requirement that would apply to the entirety of any season for which a resource clears for capacity. With a different must-offer rule, in which economic outages could be accommodated within seasons for which capacity clears, a 2-season summer-winter construct might make sense. The must-offer requirement that MISO proposes, however, would appear to prevent a 2-season approach from allowing seasonal economic suspensions. We would not support a construct change that does not reasonably accommodate such suspensions, as this appears to be a high priority for both stakeholders and MISO’s IMM.
Whether moving from UCAP to ACAP is appropriate remains to be seen. The ACAP proposal that MISO intends to include with the seasonal construct filing requires significantly more discussion, and it does not appear MISO’s current timeline will allow adequate time for this discussion. Therefore, WPPI recommends the seasonal construct filing not include this change to allow the time necessary for a careful, considered development of an ACAP proposal.
Specifically, some of the ACAP proposal items that need further discussion:
Also, we reiterate that MISO plays a significant role in determining the extent to which long-startup-time generators can contribute to resource adequacy through its control of the forward Reliability Assessment Commitment process. We call on MISO to seek to improve its forecasting and forward commitment processes to make better use of long-lead-time resources, and to keep stakeholders apprised of this work. Moreover, to the extent a generator was available to be committed by MISO, in any MISO process, any lack of MISO commitment should not affect the generator’s ACAP.
Lastly, in the Planned Outage Modeling presentation brought to the January RASC meeting (https://cdn.misoenergy.org/20210106%20RASC%20Item%2003c%20LOLE%20Enhancements%20(Outage%20Modeling)508758.pdf, at slide 3/14), MISO noted that it is counting on availability-based accreditation to “improve outage scheduling performance.” We reiterate multiple previous comments that MISO appears to be overestimating the degree to which the proposed accreditation changes will lead to improved scheduling of planned outages. According to the IMM’s own presentations, this was not a driver of his proposal, and MISO’s expectation that there will be a significant impact does not appear well founded. In its January RASC presentations, MISO ignores its own significant responsibility for outage coordination. We maintain that improved MISO outage coordination, which may include improved communication with generator owners, remains the best approach to improving outage scheduling and that it merits much more attention than MISO appears to be devoting.
WPPI supports retaining a single annual process for the Planning Resource Auction, even if MISO moves to holding independent auctions for multiple defined seasons. Also, regarding the minimum capacity requirement for PRA, WPPI does not support MISO usurping responsibility of resource adequacy from the state regulators. We reiterate our feedback, made the last time this was discussed at RASC, that adoption and design of any forward requirement should be left to the discretion of state regulators for the Load Serving Entities under their purview. To the extent there remain concerns that Load Serving Entities are relying too heavily on the Planning Resource Auction to source their capacity, WPPI suggests that MISO consider, as a first step, increasing the capacity shortage price from the current 1x the Cost of New Entry to some multiple (e.g., 3x) of CONE. Such an increase in the shortage Auction Clearing Price should incent more capacity procurement outside of the PRA.
As discussed earlier, it is important that the DA must-offer requirement allow a generator to go on economic suspension. MISO’s proposal is to retain a DA must-offer requirement such that, during seasons in which a generator has cleared for capacity, the generator may not schedule economic suspensions (i.e. placing unit out of service go on outage not for repair or maintenance, but to save money when the Market Participant projects market energy prices are not expected to cover the generator’s fuel and other relevant operating costs). We ask MISO to explicitly consider, with stakeholders, other possible approaches. For example, accommodating economic suspension for portions of cleared seasons could be implemented while granting only partial, pro rata, accreditation (for outages planned far enough in advance to be accounted for in the LOLE analysis). We would request that MISO provide fuller explanation of the relative benefits of these different approaches, and any others that may be feasible, such as allowing generators to schedule economic suspension as they see fit, with accreditation consequences handled via availability-based accreditation.
From the presentation at the Jan 6th meeting (page 12 for example) it appears that MISO's recommendation is to modify both the RA Requirements (via the LOLE model) and the Resource Accreditation to account for planned outages. However, the LOLE presentation from that same date (page 3) implies that the addition of planned outages to the LOLE model is only a temporary modification until the resource accreditation improvements can be implemented. We feel that adjusting for planned outages in both the LOLE model and the Resource Accreditation process would be double counting (double penalizing) for planned outages. Could MISO please clarify their position on this issue.
Thank You
General Comments on the Proposal
In general, the Environmental Sector appreciates that MISO has started to put forward construct options that recognize that the multiple components of the RA construct work together – namely, construct periods, number of auctions, accreditation methodology and must-offer requirements. However, MISO’s straw proposal still lacks enough detail for stakeholders to evaluate how it will function and to fully understand the proposal. We suggest MISO provide more detail, including examples of model outputs, for stakeholders as it incorporates feedback and updates its proposal. We provide a number of questions and areas where more detail is needed, below. In particular, we provide a number of questions regarding how and if MISO’s proposal would be practical for state IRP planning. MISO has previously recognized that feasibility for state planning should be included in its evaluation criteria, yet MISO’s presentation and design did not include any information on how the proposal might work for state planning. It appears that this element was not considered in the proposal design. This is a critical area of concern for the Environmental Sector, whose members are regular intervenors in state IRPs, and is a critical concern for states with resource planning or similar processes where MISO’s RA construct is a major input.
In addition, the Environmental Sector is concerned that MISO’s straw proposal is more focused on addressing near-term operations and outage scheduling issues than being optimally designed for long-term resource adequacy, and that this approach risks unintended consequences. For example, as presented MISO’s proposal is taking a long-term reliability modeling approach and essentially using that to develop a single number – PRM – for an entire season. This approach risks being economically inefficient and requiring over-building. For example, if a utility’s three-month season has a peak of 50,000 MW, do we need 50,000 MW + some reserve margin for the entirety of the season? The original idea behind LOLE is to determine whether there is enough capacity to meet demand over a certain time period, typically one or more years. If MISO already hits 0.1 d/y in its LOLE for a given year(s), then the question of whether MISO has sufficient resources is confirmed. Nevertheless, it is still important to make sure that scheduled maintenance does not impair operations/reliability, but this may be more appropriately treated as an operational paradigm (potentially paired with accreditation design). We know enough capacity has been built, but we now need to ensure it is available and operated properly when it is needed. It is still useful to look at the impact of maintenance on LOLE so that LOLE is not compromised, but that seems that MISO could calculate the maximum amount of capacity (UCAP or adjusted ICAP) that could be out of service in each hour or day, and make plans accordingly. Any maintenance schedule that causes LOLE to increase from its “base” level (base level calculated in the annual optimized 0.1d/y case) is a schedule that should be rejected or penalized in accordance with MISO’s scheduling authority.
Seasonal Resource Adequacy Requirements
First, we ask that MISO provide detailed modeling demonstrating how its proposal will be implemented in the first, applicable PRA. We would also ask MISO to provide a hypothetical example of how an individual utility would include the proposed construct in an Integrated Resource Plan. A significant portion of this process has been developing reliability metrics and scenarios that would be used to evaluate different construct options; however, we believe that it would be useful to provide specific modeling examples and output data so that stakeholders can better understand the implications of these metrics and proposed targets. We suggest that MISO continue to provide analysis, including a reasonable number of hourly LOLE analyses for the different seasons and designs MISO is proposing to help inform whether the seasonal PRMs that are being proposed meaningfully match up with the risks in the LOLE analysis.
Second, we reiterate that how MISO “[p]erform[s] separate LOLE analysis to meet respective seasonal LOLE risk targets” (slide 16), is critically important for reasonable outcomes and seasonal requirements. Our understanding is that if the LOLE finds no risk in a season, then it would assign a 0.01 LOLE to that season. First, this begs the question of why that season would have a PRM above an LSE’s coincident seasonal peak if there’s no risk? Second, if artificial risk is being assigned to a season to accommodate a seasonal design, this addition of artificial risk in turn creates a risk of overbuilding to meet that artificial risk. Therefore, if MISO moves forward with a seasonal construct, we suggest MISO adopt an LOLE approach that creates as little artificial risk as possible. For example, seasons where the LOLE finds no risk under a 0.1 day/year approach, MISO could consider extrapolating out to three or four significant digits to see if LOLE-derived risk (as opposed to artificially-created risk) emerges. Finally, MISO could consider that when the LOLE finds no risk in a season, that the PRM for that season could be zero and an LSE’s RA obligation would be equal to its coincident seasonal peak.
Availability-Based Accreditation, Including the Proposed UCAP/ACAP Conversion Ratio Methodology
MISO’s straw proposal’s seasonal RA design with seasonal PRMs, in combination with its proposal to use UCAP and ACAP raises a number of questions, primarily related to state planning feasibility. We ask that MISO provide responses to the following questions before the next RASC meeting or in the next RASC meeting materials:
1. Is the intention that the UCAP and ACAP PRMs would each be applied in an IRP model as binding constraints? Would the former apply only to renewables and LMRs and the latter only to thermal generators?
2. If so, most utilities assume an option for short-term capacity purchases to cover temporary shortfalls. Under MISO’s proposal would LSEs now need two capacity purchase options, one to satisfy the UCAP PRM and one to satisfy the ACAP PRM?
3. We do not believe that most IRP models are set up to simulate two PRM constraints applying to different resources. IRP models can generally model PRMs and accreditation values seasonally, but MISO's proposal would seem to require more than that -- PRMs that discriminate between resources.
4. We’re not clear why MISO would not just change the determination of UCAP for thermal resources to account for the availability factors that ACAP is trying to capture (e.g., planned outages). Otherwise, one would seemingly end up with IRP modeling that uses UCAP values for renewables and LMRs and ACAP values for thermal generators, which would not be consistent metrics, and would create unnecessary confusion, in addition to not being currently feasible.
5. What is the purpose of the UCAP/ACAP conversion ratio?
6. Would an individual utility still apply its coincidence factor to each PRM?
7. How would MISO recommend that utilities project ACAP generator values going forward understanding that most state planning proceedings plan for at least 10 years into the future? Simply assume that the historical value applies? And will each utility be able to calculate its own generators' ACAP values or will those have to be updated each year on a fleetwide basis and apportioned to individual generators by MISO, similar to the current process for wind accreditation?
Day Ahead Performance Obligation, Including Treatment of Resources with Sub-Annual Operation
The Environmental Sector supports and appreciates MISO’s focus on creating more flexibility for resources to utilize sub-annual operation, particularly for coal plants seeking to idle for parts of the year. However, we believe this flexibility does not require an RA construct design with multiple seasons. As discussed above, once the 0.1d/y target is confirmed for the year in question, ensuring that the system can reliably operate requires a more granular analysis that can account for potential unit commitment and dispatch feasibility.
MISO states that an annual construct reflecting sub-annual risk has the “Least flexibility on intra-year changes and less explicit accommodation of seasonal operation” compared to other options. (Slide 14). This recognizes that an annual construct can accommodate extended idling and we believe that MISO’s current proposal for Day Ahead Performance Obligation could be used in an annual construct for resources LSEs designate for extended idling before the auction, particularly under an ACAP paradigm or a similar accreditation methodology. In short, we support increasing flexibility for resources to utilize sub-annual operation, but do not find that there is sufficient rationale to suggest that doing so supports a seasonal RA construct.
MISO RASC FEEDBACK
January 20, 2020
Pointe Coupee Electric Membership Corporation (PC Electric), Southwest Louisiana Electric Membership Corporation (SLEMCO) and Concordia Electric Cooperative Inc. (Concordia) submit the following comments on the Planning Resource Auction Resource Alignment proposal IR094.
PC Electric, SLEMCO and Concordia (Louisiana Cooperatives) are transmission-dependent rural electric cooperatives in Louisiana and Load Serving Entities located in Zone 9. We have concerns about the portion of the proposal that has to do with introducing a minimum capacity requirement, as presented in the January 6, 2021 presentation to the Resource Adequacy Subcommittee on “RAN Reliability Requirements and Sub-annual construct” (Slide 19). This is a proposal to require LSEs to procure at least 50% of their PRMR from within the LSEs load zone prior to the auction. In our opinion, this aspect of the proposed reliability construct changes has to date not received sufficient analysis and explanation comparable to the analysis of rationale, risk, and mitigation presented for the other parts of the proposal. Questions not addressed include:
As cooperative utilities dedicated to providing least cost service to our customers, we believe this proposal requires much more analysis and consideration to make sure it in fact serves reliability and customers. Once a more detailed analysis is presented, it will be important to allow time for review and comment. If necessary, in order to allow time for proper review and consideration, we would urge it be broken out and considered separately from the other proposed RA construct changes.
MGE, MPPA, and SMMPA generally support WPPI Energy's feedback.
More informally, some LSE Coalition members are preliminarily concerned about using both capacity accreditation as well as LOLE Study generator outages to address resource adequacy needs and the potential for inefficiently and unfairly "double counting" outages.
Thanks,
David Sapper
dsapper@ces-ltd.com
In addition, also more informally, some LSE Coalition members do not support raising the PRA scarcity price or need more time and information before commenting.
Again, sorry for the confusion of feedback amendments.
David Sapper
dsapper@ces-ltd.com
MISO RASC Feedback
Big Rivers Electric Corporation
Hoosier Energy Rural Electric Cooperative
Southern Illinois Power Cooperative
Dairyland Power Cooperative
January 20, 2021
Big Rivers Electric Corporation, Hoosier Energy Rural Electric Cooperative, Southern Illinois Power Cooperative, and Dairyland Power Cooperative (“The Respondents”) thanks MISO for the opportunity to provide feedback on the proposed sub-annual resource adequacy construct changes, specifically:
1. General comments on the MISO proposal
2. Seasonal resource adequacy requirements
3. Availability-based accreditation, including the proposed UCAP/ACAP conversion ratio methodology.
4. Planning Resource Auction (PRA), including minimum capacity requirement for PRA
5. DA performance obligation, including treatment of resources with sub-annual operation
At this juncture, the Respondents still do not have the enough information to have a position either for or against all of MISO’s proposed changes to the PRA. While the Respondents are open to MISO’s hypothesis that the changing resource mix within the region requires changes to the PRA and the risk profile of the LOLE study, we still believe that MISO’s analysis lacks the requisite cost/benefit analysis that would convince us that these changes are necessary. The Respondents are customer-owned member cooperatives, therefore ensuring we provide our members with the reliable capacity at the lowest cost is incredibly important. Thus, the Respondents are concerned that this proposal will only raise capacity prices in the region by reducing the amount of available supply and increasing the Planning Reserve Margin Requirements (“PRMR”) in both individual Local Resource Zones (“LRZ”) and the entire region without an increase in reliability. While we’re concerned about these over-arching issues of maintaining reliability at lowest cost, below are our initial thoughts on the changes MISO proposes with emphasis on minimum forward capacity requirement and the ACAP accreditation methodology.
Minimum forward capacity requirement: The inclusion of a minimum forward capacity requirement in this in the proposal took the Respondents by surprise, especially the fact that it applies to their load’s Local Clearing Requirement (“LCR”) rather than the LSE’s total load. While this was discussed at a prior RASC meeting, the tone seemed much more exploratory than something that would be included in MISO’s initial proposal without additional vetting with stakeholders. The Respondents have several questions on the minimum forward capacity requirement of 50% MISO is proposing:
Given all the outstanding questions, the lack of justification by MISO for the proposal, and being included in the proposal without proper vetting, the Respondents do not support the inclusion of a zonal minimum forward capacity requirement at this time.
Accreditation: Respondents require more information to either support or oppose the Availability-based accreditation at this time. While it seems reasonable to base accreditation of resources on their availability during MISO’s most critical RA hours, the Respondents await information that shows how their individual portfolio of resources will be impacted by this change and the impact on the entire footprint’s available capacity. Without this information it is impossible to determine the cost impact this may have on the Respondent’s customers and whether this change will either raise or lower their capacity costs. MISO should provide both individual LSEs with their UCAP to ACAP conversion for the RA hours MISO chooses to determine the impact on their own accredited values, the ACAP in each LRZ, and the ACAP of the entire MISO footprint. Additionally, MISO has not provided stakeholders an overview of the proposed methodology proposing for determining the RA hours. This is critical since those hours will determine ACAP accreditation in the new framework.
The ACAP methodology should ensure the legacy resource’s capacity is not unduly diminished in favor of new resources. Existing resources were planned and built by utilities under the existing RA construct or prior to the MISO capacity market and their value should not be understated. Without knowing how the RA hours are calculated and their impact on our portfolio of resources, the Respondents do not have the information needed to support MISO’s proposal. MISO needs to ensure these two items are thoroughly vetted with stakeholders before moving forward.
The Respondents are also interested in knowing how wind and solar accreditation will be affected by the ELCC method in the different seasons and how the changes to that analysis will affect reliability in conjunction with the proposed changes.
The Respondents believe that while a change to the PRA from the current Annual construct to a Seasonal construct more appropriately accounts for the changes in load over the course of the Planning Year, the allocation of LOLE risk, PRMR for each season and the number of seasons are concerns that are still outstanding. The reliability target in each season should not be overly conservative to require more resources than are required to meet 1 event in 10-year reliability in each season and any changes to the modeling of outages do not negatively impact reliability. Similarly, the PRMR in each season should be appropriately calculated so as to not intentionally raise costs to customers without a corresponding reliability benefit. The changes should not create volatility in the PRA that cannot be anticipated by LSE that require regulatory approval for any capacity changes that might be required and give LSEs time to adjust their portfolios for the change. The Respondents would also encourage MISO to minimize the administrative burden on LSEs for the change. At this time, the Respondents do not have a preference on the number of seasons and await MISO’s justification for their decision.
Regarding the must offer requirements in the proposal, the Respondents believe MISO should allow flexibility for LSEs to economically shutter units during seasons in which they are not needed. This flexibility will allow LSEs to reduce costs without affecting reliability. Accreditation for these units should only be adjusted for the season(s) in which they do not bid into the PRA. For other seasons their accreditation should not be impacted. New intermittent resources should be accredited to the extent they support the system, especially in shoulder seasons, allowing legacy (often baseload) resources flexibility for maintenance and possible seasonal shutdowns if economical. This would allow a level of flexibility not available in the current PRA.
The Respondents also have a couple of additional comments on the overall impact of this proposal. Utilities that require regulatory approval of capacity additions or retirements put a lot of time and effort into those decisions and require time to get them approved with their regulators. MISO needs to keep this in mind with the time frame it proposes with changes to PRA and needs to allow adequate time for utilities and their regulators to adapt to the changes made. Another consideration that also needs to be in the forefront of these changes is how volatility, in both market prices and the accreditation utilities get for their resources, may push utilities to make uneconomic decisions as they are making changes to their resource portfolio to accommodate regulatory deadlines. MISO needs to try and accommodate the timelines utilities need for these approvals into this proposal as much as possible, especially with a change as large as this.
In conclusion, due to the lack of detail around the justification for the 50% zonal minimum forward requirement, the Respondents are opposed to this portion of the proposal at this time. With regards to the remainder of the proposal, given the number of outstanding questions and the lack of detail around the number of RA hours MISO will be using, the impact these changes will have on customers, and number of seasons, the Respondents at this time do not have a position on the proposal and require more details before making an informed decision.
Thank you in advance for considering this feedback.
MISO RASC Feedback
Big Rivers Electric Corporation
Hoosier Energy Rural Electric Cooperative
Southern Illinois Power Cooperative
Dairyland Power Cooperative
January 20, 2021
NIPSCO appreciates the opportunity to provide feedback to the RASC on the following items outlined from our January meeting.
NIPSCO believes there are many changes occurring at once instead of identifying system stress inducers and applying a targeted solution one issue at a time. These changes include outage modeling in LOLE study, availability-based accreditation, and seasonal resource adequacy requirements
We support a 4 season construct reflecting sub-annual needs with seasonal requirements, and one annual auction for seasonal periods. Availability-based accreditation issue can be address by calculating UCAP using forced outage rate (XEFORD) that includes all outages during historical RA hours
PRM/LRR requirement is on a seasonal base and calculated using optimal planned outage assumptions then calculate UCAP using forced outage rate (XEFORD) that includes all outage during historical RA hours will eliminate UCAP/ACAP conversion requirement.
What was the rationale behind Load Serving Entities would be expected to procure prior to the auction at least 50% of their PRMR?
Resources used to meet this requirement should be within the zone to ensure that the LCR requirement is also met – Is not this covered by current PRA rules?
Do RA hours count against resource for the seasons in which they are not cleared?
How will the IMM treat resource for the seasons in which they are not cleared for physical/economical withholding and market power?