SAM 2.0 Stakeholder Comment Matrix

Transcription

1 SAM 2.0 Stakeholder Comment Matrix The AESO welcomes stakeholder input on the working group conclusions and discussion context contained in Section 5 of SAM 2.0. Please review the following instructions and submit your feedback to capacitymarket@aeso.ca no later than 3:00 p.m. on Friday, September 15, The AESO will post all feedback as received on by September 19, Instructions: Stakeholders are encouraged to provide all feedback on SAM 2.0 within this document only. Specific feedback on key design questions, working group conclusions and discussion context will not be accepted in any other form. General comments about the overall technical design of the capacity will not be accepted. If it is necessary to submit additional supporting documentation, please clearly indicate which design question, conclusion, discussion note or stakeholder comment your document refers to. No handwritten comments will be accepted. Input your name, organization you are representing, and feedback in the comment boxes below each key design question. Your contact information is requested in each section for ease of sorting and compiling feedback from all stakeholders. Press Shift + Return to enter paragraph breaks within a comment box. Comment boxes will automatically expand if additional room is required for feedback. If you have any questions about this comment matrix, please capacitymarket@aeso.ca. Page 1

2 Eligibility Who can provide capacity? How much can they provide? Eligibility & Capacity Value Determination All eligible capacity must offer into the capacity auctions. Eligibility will allow all new and existing supply resources to offer their approved UCAP into the capacity market. REP1 will not be eligible. Future REP rounds will need to be evaluated based on contract. Carve-outs by technology will not be allowed. Unforced Capacity (UCAP) MW should be used to represent capacity when determining capacity values. WG unanimously supported the capacity market using a UCAP calculation, subject to the detailed calculation of UCAP and AESO s ability to implement a UCAP model. UCAP calculations done on an individual asset basis were preferred relative to those based on asset class while recognizing potential differences for new versus existing assets. A final recommendation is expected by SAM 3.0. Details of specific UCAP calculation methodologies for different asset types will be initiated for SAM 3.0. WG had strong directional alignment with SAM 1.0 position that REP Round 1 resources will not be eligible. Demand resource may participate by bidding into the capacity market as part of the demand curve. Import terms for participation must be examined. Export will not be eligible. Deliverability will be a single zone. If a deliverability constraint is identified prior to the auction, resources in the constrained area will be selected by offer price. WG has generally agreed with SAM 1.0 position that a wide range of technologies should be allowed to offer into the capacity market and carve-outs for certain technologies should not be allowed. Detailed examination of storage and aggregated resources, including a recommendation on eligibility, is planned for SAM 3.0. The WG discussed demand side resource participation (excluding energy efficiency) in detail. Directional alignment with the starting point was not achieved and additional alternatives have been proposed for consideration before a final recommendation is made. The additional alternatives are: load should be able to participate on supply side or both supply and demand side. A final recommendation, including treatment of energy efficiency, is expected by SAM 3.0. Intertie participation in the capacity market has not yet been discussed in detail. A recommendation on intertie eligibility is expected by SAM 3.0. Deliverability constraints have not yet been discussed in detail. Further discussion on this item is planned for SAM 3.0. Minimum size requirements for participation were discussed but a recommendation has not been reached. WG has discussed alternatives (150 kw, 2 MW, and 5 MW). A recommendation is planned for SAM 3.0. Feedback: UCAP The REA WG supports the assertion that UCAP should be used to determine an assets capacity value provided that the UCAP is calculated for each based on historical data for the assets. UCAP methodology is expected to provide capacity values that account for the seasonality of capacity resources. However, other attributes such as ramp rate should not be included as components used toward UCAP determination. The UCAP calculation for Co-generation assets should differ from the standard NG generation assets, potentially using a net-to grid UCAP calculation for co-generation located behind-the-fence (BTF). The calculation of UCAP on a net-to-grid basis The REA WG is in agreement with demand response resources participating in the capacity market provided they are subject to the same obligation structure as supply side capacity resources. Page 2

3 The REA WG agrees that REP Round 1 resources should not be eligible for capacity payments in addition to what the RESA provides. would like to see the implementation of a methodology for accounting for REP resources in the demand side of the capacity market that ensures that there is no distortion of clearing price for all other capacity resources. The REA WG believes that the minimum size should be based on the tradeoff of allowing the maximum number of participants to partake in the auction but weighing this against the administrative burden to determine the asset s qualifications. SAM 1.0 Key Design Question SAM 1.0 Starting Points SAM 2.0 Working Group Conclusions SAM 2.0 Working Group Discussion Context Procurement Timing & Frequency When and how often will capacity be purchased? Market Mechanics Three year forward period (Base Auction will be held three years prior to start of the commitment period). Base Auctions held annually. One Rebalancing Auction will be held one year prior to start of commitment period. Three year forward period (base auction will be held three years prior to start of the commitment period). Two rebalancing auctions will be held between the base auction and the start of the commitment period. The final rebalancing auction will be held as close to the commitment period as practical. The rules should not provide flexibility to add conditional rebalancing auctions. WG has generally agreed with SAM 1.0 starting point of three year forward period and recognized that a transition period will be required to get to a steady state. A final recommendation on forward period is expected by SAM 3.0. WG members were generally not aligned with the SAM 1.0 position of a single rebalancing auction, preferring instead multiple rebalancing auctions, one of which was as close to real time (i.e. the obligation period) as practical. Subject to implementation timelines, a likely schedule is: Base auction: 36 months before obligation period Rebalancing auction 1: 15 months before obligation period Rebalancing auction 2: 3 months before obligation period WG members were generally aligned that there should not be additional flexibility in the rules to add conditional rebalancing auctions. Impacts to capacity deliverability due to delays to in-service dates of new transmission projects will be reflected in pre-scheduled rebalancing auctions rather than adding additional auctions. WG members were generally aligned that rebalancing auctions should be held as scheduled even if it is deemed that the AESO does not need to adjust its position. A final recommendation on rebalancing auction timing and parameters is expected by SAM 3.0. Page 3

4 Feedback: The REA WG supports a forward period of three years and the proposal for two rebalancing auctions between the base auction and the start of the obligation period. agrees with holding one rebalancing auction near the mid-point of the forward period in alignment with the AESO demand forecast timing and a 2 nd auction as close as possible to the obligation period as practical. believes that for the rebalancing auctions to function correctly there must be a robust market for capacity and it must a be a traded product with a high degree of liquidity. Rebalancing auctions should occur even if the AESO does not need to procure/sell capacity the auction should have the functionality to allow market participants and capacity resources that have known change in operations to use the last rebalancing auctions to buy/sell capacity and adjust their positions accordingly. Page 4

5 Term How long will the capacity delivery period be? Market Mechanics One year, non-seasonal commitment period for all assets. One year (or one season if a seasonal product is chosen) commitment period for all assets. The obligation period should not vary based on resource type or vintage. There was general but not unanimous agreement by the WG that resources should not be treated differently with respect to the length of the obligation period term and that the term should be relatively short. This was discussed in terms of both vintage (new, existing, refurbished) and type (non-variable, variable, demand side, storage, interties, etc.). There was unanimous agreement that the obligation period should not vary by resource type (i.e. fuel type). There was general agreement that the obligation period should not vary by vintage (i.e. existing, new, refurbished) but some WG members did not agree, indicating that it may make sense to provide new resources with the option to lock-in revenue for a period longer than one year or season. A final recommendation on obligation period term and whether there is any differentiation based on resource type is expected by SAM 3.0. Feedback: Obligation Period The REA WG does not believe an obligation period of one year will entice new investment in generation to the province which is one of the stated goals of the capacity market. We are off the opinion that the only length of obligation period that could actually entice new investment and reduce the long-term cost of capacity to consumers is a seven year term. The proposed one year term only incents the existing generators in AB to convert or build new assets, Essentially we are creating a market that keeps investment out of AB and likely drive the cost of capacity up in the long term. understands that in the current state of oversupply the one year term may be optimal, but would like the steady state obligation period of seven years to be revisited in this SAM iteration. The obligation period should not vary by resource type but we would be open to allowing new resources the option to lock in for a seven year term. Page 5

6 Cost Allocation How will capacity costs be allocated? Working Groups: Eligibility & Capacity Value Determination Procurement & Hedging Capacity costs will be considered separately from wires and ancillary services costs and all customers will continue to face wires and ancillary services costs. Cost allocation will consider energy usage at system stress performance periods and coincident peaks. Customers can hedge capacity costs through financial methods. The WG directionally supported the starting point that capacity costs will be considered separately from wires and ancillary services costs and all customers will continue to face wires and ancillary services costs. Cost allocation discussion is limited to capacity costs. WG members require additional information and/or technical expertise to establish the detailed allocation design but the assumption is that cost allocation will follow principles such as cost causation and providing efficient signals. A number of alternatives were identified in addition to the starting point. The starting point and alternatives will be examined in more detail for SAM 3.0. The WG reviewed whether the cost allocation calculated by the AESO should be recovered through a wires level tariff or retail settlement. WG members with a preference generally preferred capacity costs flowing through the retailer. Other WG members were indifferent or required further information. Further discussion is planned for SAM 3.0. Feedback: Cost allocation will consider energy usage at system stress performance periods and coincident peaks, while the REA WG does support this, due to settlement structure in province this is essentially punishing those who are unable to singularly move the meter on their demand. While the REA WG does not deny that the individual consumer s consumption during peak demand periods contributes to the capacity needs of the system. The bulk of REA sites are not metered/settled in a manner that would allow them to avoid capacity costs by decreasing energy usage at system stress performance periods. Further, as lighting load drives the majority of system stress points in the winter, this creates even less of a causal relationship for the REA members in regard to their effect on the system stress. An allocation methodology that utilizes these peak demand periods to determine the costs for consumers only creates the incentives required for consumers to shift their usage away from peak hours if we make a major shift in the metering base of the province, putting in place a system that has DIM meters to a much lower kva level or even to all sites. Moreover, if capacity costs are flowed through to Wires companies as bulk costs and they are allowed to determine how these costs/savings are applied to their rate base it will degrade any causality that customers should feel from overconsuming or restricting usage during these periods. The REA WG is somewhat confused as to what would be different in recovery through a wires level tariff or retail settlement as the Retailers are responsible for the recovery of all energy costs through invoicing of Distribution, Transmission and Energy charges, the REA WG feels that potentially further detail as to the benefits/costs of each methodology need to be evaluated. Consumers will the ability to self-supply should not be forced to procure capacity from the AESO (or through the auction) if there are more cost-effective options available to them. Page 6

7 Performance Assessments How do we know that capacity has been provided? Eligibility & Capacity Value Determination Performance will be measured during capacity performance periods established at system stress conditions starting near to declaration of EEA1. Thresholds for warning notification and performance period start notification will be defined and information will be communicated on a new Supply Adequacy Report to be determined. A pay for performance program will be established where underperformers will compensate over performers on a revenue neutral basis. Performance penalties will be a multiple of Net CONE. WG generally agrees that the capacity market should have financial consequences for under performance and incentives for over performance. The WG will consider a revenue-neutral pay for performance program vs. a program where consumers are reimbursed for under performance. The issue will be discussed in more detail for SAM 3.0 as will specific terms and conditions of performance. The WG was not aligned with the starting point that system performance periods will be defined near EEA1; however, the design element was not discussed in detail. Detailed discussion is planned by SAM 3.0. Penalties as a multiple of Net-CONE requires additional clarity and was generally disagreed upon by participants as it is currently defined. The issue will be discussed in more detail for SAM 3.0. Name: Tory Whiteside Organization:. URICA Energy Management on behalf of the REA Working Group Feedback: The REA WG agrees that there should be financial consequences for under performance and corresponding incentives for overperformance in the capacity market. The REA WG supports the use of a performance based incentive and penalty regime, and would like to see further information and discussion of a potential structure in the next iteration of the SAM However, as the implementation of a performance based regime has significant implications for other design elements that are interrelated such as UCAP methodology, Cogen treatment and must-offer requirements the creation of pay for performance based program will need to account for these dependencies and will need well defined force majeure standards such that generators no exactly what the outcomes are in advance of any events. The REA WG supports the continued discussion of a penalty structure that is outside the initially proposed multiple of NET Cone methodology. Page 7

8 Market Mechanics How will the capacity market work? Market Mechanics Centralized capacity market. Single Price Sealed-bid Auction. All eligible existing resources must offer and their offers must be below a maximum offer cap. Market power mitigation for capacity market offers will take the form of an offer cap applied to all existing resources. The capacity offer cap will be applied equally to existing resources as a fraction of Net-CONE of the reference technology. No capacity offer floor. Asset substitution allowed after rebalancing auction should supply resources be unable to meet their capacity obligation in the delivery year.* Centralized capacity market. Existing and new resources will participate in a single auction. Separate auctions will not be held for new or existing resources. The WG discussed sealed-bid auctions as well as descending clock auction formats. Additional discussions are required on these before a final recommendation can be made. A final recommendation on auction type is expected by SAM 3.0. The WG was not aligned on the use of an offer cap to mitigate market power, although this design element was not discussed in detail and only preliminary discussions were held. The WG noted that an exception application process is likely required if a standardized cap is adopted. More detailed discussions on this topic will be held for SAM 3.0. The potential for several interdependencies with the other design streams regarding market power mitigation approaches was flagged and the requirement for further follow-up identified. (Note: A mapping of currently identified interdependencies is provided on pages 12 and 13.) Discussion regarding offer floor will commence for SAM 3.0. * This starting point was included with the Eligibility key design question in SAM 1.0 Information on the potential of utilizing a Minimum Offer Price Requirement (MOPR) to address the potential impact of renewable support payments or other out-of-market capacity payments on price fidelity in the capacity market was briefly presented to the WG. The issue will be discussed in significantly more detail for SAM 3.0. In testing the starting point, the group generally agreed that asset substitution should be allowed after the final rebalancing auction but the concept has not yet been discussed in any detail. A working assumption is that substitution will be on a like-for-like basis; i.e. resources need to have same or greater capacity value but do not have to be the same resource type. Further discussions on this item are planned for SAM 3.0. Feedback: The REA WG supports a centralized capacity market provided flexibility exists to all customers the potential to manage their own capacity needs. The final market design should ensure that capacity asset owners, can price the risk associated with participating in the capacity market into their offers. It is also necessary that capacity asset owners, and potential investors have the opportunity to recover their costs, including potential historical losses pre-market inception and a reasonable rate of return for the market to hold the potential for an equal playing ground for existing market participants and potential new entrants. The REA WG believes the use of any auction methodology that shows offer transparency is far more appealing than a Single Price Sealed-bid Auction. The REA working group believe that asset substitution is a foundational criterion for the market to succeed and the determination of the logistics and structure of asset substitution is extremely important to the management of other interrelated elements in the design. The finalization of this during the next SAM iteration would be very beneficial to developing structure in other areas such as penalty structure, UCAP, The REA WG does not support an offer cap for existing resources in addition to the cap set by the demand curve. Excessive mitigation in the capacity market will discourage investors from participating if they view that the mitigation will prevent them from recovering their costs, and earning a reasonable rate of return over the life of their asset Page 8

9 The REA WG is particularly concerned with excessive mitigation in the context of a must offer obligation. If a capacity resource cannot reflect its perceived delivery risk for the capacity it is forced to offer, the resultant clearing price will be artificially low. Artificially low capacity prices will negatively impact the investment signal and reduce income to existing resources leading to units either early retiring or mothballing. The impact of which has the potential to negatively impact the reliability of the system as we move into the medium term. The REA WG supports the continued review of the use of a MOPR to address the potential impact of renewable support payments or other out-of-market capacity payments on price fidelity, but does not believe a MOPR should apply to Cogeneration based on the presentation of facts to date The REA WG supports allowing capacity resources to offer multiple blocks for an individual resource in the capacity auction. This may make capacity volume clearing easier at the auction and will help capacity resource owners to better reflect risk and uncertainty associated with their entire facility using a stratified offer strategy. Page 9

10 Obligation to Procure Who will buy the capacity? Procurement & Hedging In general, AESO will hold the obligation to procure capacity on behalf of load. AESO as a central agency will procure capacity to meet load needs net of self-supply. Loads with BTF generation will be treated as a net to grid combined facility and as such can opt out of capacity charges if they continue to operate as a combined facility. Financial incentives will encourage load consumption to be aligned to generator availability. Physical bilateral procurement is not allowed. While expected to be a policy direction, in general, the WG concluded that AESO will hold the obligation to procure capacity on behalf of load. Physical Bilateral procurement (as currently defined) is not allowed. The WG requires further consideration on loads with BTF generation treated as net-to-grid for capacity obligations, and this treatment is termed self-supply. The WG discussed the working definition of Self-supply and agreed in concept; however, this definition requires further work: "Self-supply is defined as generation and load not settled through the current energy market due to an arrangement that allows for the production and consumption of energy within the site with only the net component of that supply or demand subject to AESO settlement. This includes energy at sites connected by the transmission network that is settled on a totalized basis due to the presence of a DAT. With self-supply, generation and load that would not attract pool and/or real-time transmission charges/credits can voluntarily elect the same net treatment within the capacity market, removing both the supply and demand from the AESO administered capacity market." The WG discussed the working definition of Physical Bilateral capacity procurement and agreed in concept; however, this definition requires further work: Physical Bilateral procurement is a contractual arrangement between a load market participant and a specific (named) capacity resource utilizing the transmission or distribution system for physical delivery of all or a portion of the load s capacity needs, which would remove both the supply and demand volumes from the AESO administered capacity market. The WG agreed that if self-supply is permitted, then the self-supplier should carry their share of the resource adequacy requirement. How that is determined requires further discussion. Feedback: The REA WG recognizes interdependency with net-to-grid participation and the UCAP calculation methodology for Cogen assets. As stated previously this will require Cogen assets to be evaluated via different UCAP methodology than other natural gas assets. However, the REA WG supports the ability of industrial consumers with behind the fence generation to continue their participation in the market on a net-to-grid basis. The REA WG agrees that physical bilateral procurement should not be allowed, nor does the concept make a lot of sense even notionally. The REA WG notes the Procurement and Hedging WG group discussed the requirement for net-to-grid sites to carry a reserve margin. However, provided their UCAP considers the historical net-to-grid amounts, - historical net-to-grid levels at least to some degree reflects the probability that the industrial load will import/export from the grid. If these costumers are willing to use these historical measures in their UCAP calculations, then there should not be a requirement for the industrial consumer to carry a reserve margin.. Page 10

11 Capacity Market Settlement How will capacity providers be paid? Procurement & Hedging Credit will be required for capacity value both on load and new supplier side. Net Settlement will be facilitated against CFD hedges. Penalties will be collected as part of settlement cycle. Settlement will continue on a monthly basis. The WG requires further discussion on whether financial hedges should be facilitated by the implementation of Net Settlement instructions within the centralized market. Feedback: The REA WG supports the AESO facilitating Net Settlement Instructions within the centralized market only if the cost/benefit makes sense. If there are other options for settlement of capacity the REA WG would be interested in hear what methodology the AESO is considering. The REA would like to see more information regarding the actual need for capacity NSIs, within the structure of asset substitution and auction settlement, along with any alternatives that are being considered. Page 11

12 Resource Adequacy Requirement How much capacity needs to be procured? Adequacy & Demand Curve Determination Assumption: Government will set a physical resource adequacy requirement with target values established for Expected Unserved Energy (EUE) and Loss of Load Hours (LOLH). Target capacity volume established based on probabilistic resource adequacy requirement and considerations for supply adequacy impacts of resources regardless of their capacity market eligibility. Downward sloping, convex demand curve with Price cap at greater of Gross Cone or Pre-determined multiple of Net-Cone. Capacity target creates inflection point at price of Net-Cone. Recommendation regarding the resource adequacy criterion and the reliability measure to be used is not requested from the WG; expected to be a government policy decision. However, the WG wishes to provide input into the criteria decision process, either through a separate consultation process or the WG process. Target procurement volume to be based on probabilistic resource adequacy requirement modelling considering supply adequacy impacts of all resources regardless of their capacity market eligibility; details will be reviewed through the work group (WG). Demand curve will be downward sloping. Demand curve should have the appropriate governance and oversight; how to be determined. EUE and LOLH are acceptable measures but alternatives should be evaluated. Generally agree with the AESO as the responsible party for modelling reliability requirements subject to appropriate governance. Beyond agreement on downward sloping curve the WG has not demonstrated directional alignment on the other components of demand curve to date; further discussion is required. Determination of estimated energy and AS revenues identified as critical to the estimation of net-cone and overall demand curve; dependent on Energy & Ancillary Services design. General agreement by the WG that the price cap should be a multiple of Gross Cone; will require additional discussion and analysis to determine how to calculate the multiple of Gross Cone. Minimum and maximum capacity volumes with (Target Minimum) < (Maximum Target). It has been noted that governance has immediate-term and long-term considerations to be addressed. Immediate term: what is the oversight of the technical design work on the reliability requirements model for the technical design of the capacity? Long-term: what is the ongoing oversight of the reliability requirement model and demand curve, and the key variables that will impact stakeholders in the capacity market? The WG needs to determine if the reliability requirement is annual or seasonal. Feedback: The capacity demand curve and resource adequacy targets are a fundamental component of the market redesign. The REA WG suggests that AESO undertake an analysis that models the impact of different demand curve parameters to ensure the ultimate design results in an efficient outcome. The REA WG supports the development of a downward sloping demand curve for which the slope and intercept of the demand curve reflects the willingness to pay for incremental capacity. The REA WG also supports the presence of regulatory oversight associated with setting the demand curve (and the reference technology cost that underpin it), and its parameters as investor confidence will be a function of the credibility of the process for setting the demand curve. The REA WG supports further research on the seasonality component, but is of the belief that the determination of a UCAP that accounts for this and will be based on summer availability will necessitate thee existence of robust financial bilateral market for capacity. Give this the REA WG believes the AESO could use the single demand period originally suggested. Page 12

13 Inter-operability implications How will the capacity market impact the energy and ancillary services markets? Energy & Ancillary Services Market Changes Cost based energy market offers. Continue unit self-commitment. Capacity providers must offer, all others may offer. Raise price cap and introduce Operating Reserve Demand Curve (ORCD) to better reflect scarcity pricing. Dispatch flexibility incented via energy or ancillary services markets rather than capacity market. Roadmap for future market changes to address increased intermittency to include consideration of RUC / BDAM / shorter settlement interval and possible other AS products. All SAM 2.0 WG conclusions are based on Phase I analysis (i.e. assuming current system assets with introduction of capacity market). See Section 3: Roadmap for Energy and Ancillary Services Markets for details. Can continue unit self-commitment. AESO should approve outages for capacity committed resources. All supply capacity (committed and other) must offer physical availability (similar to rules today on offering MC subject to an AOR). This includes loads that may be committed on the supply side of the capacity market. If a cost-mitigated model is chosen, scarcity and shortage pricing mechanisms would be part of this model. Further work is required. No changes to AS products, markets, operations at this point. Phase II (based on net demand variability studies and further market efficiencies) to be tested by Q These conclusions plus the Phase I conclusions will then be used for input into development of a future market roadmap. General alignment that net demand variability modelling will assist in understanding issues and timing of roadmap options. WG split on offers mitigated based on cost vs. other market mitigation options (e.g. structure, offer caps). Will discuss offer obligations in more detail for SAM 3.0 as part of further understanding on offer mitigation, pricing scarcity and shortfalls, and further discussions on other potential market efficiencies. Added question related to interties offer obligations in energy market if deemed to be capacity resource eligible. Added question related to offer obligations (if any) for ancillary services. The ability for the AESO to cancel a planned outage or a mothball outage, or to direct a long lead time asset to start, is still required for system reliability reasons. Further work required on mothball units / long lead time energy / non-capacity resources. If an outage is approved by the AESO, the capacity resource may be exempt from capacity performance penalty if the performance event occurs during the outage period. (Note: interdependency with Eligibility working group). Will examine if there are other options for non-committed resources to provide visibility, as an alternate to must offer. Requirements for load resources that clear on the demand side of the capacity market need further review; may have must offer obligation. With respect to cost mitigation, the working assumption was the overall markets require sufficient revenues to provide return on capital. In addition to items already in scope, price floor considerations likely part of that examination. Feedback: Outage Scheduling - The REA WG supports the capacity resource owner having the option to request approval for an outage from the AESO provided that if the outage is approved then the resource is exempt from financial penalties if not available during a capacity performance event that coincides with the outage. The REA WG is extremely concerned regarding the rules and constructs around intertie offer obligations due to the potential for economic withholding of tx by the owners. The REA WG proposes that generators should continue to be permitted to schedule planned outages without the AESO s approval. At the same time, a capacity resource should have the option to request approval from the AESO if it wishes to ensure it is exempt from its capacity obligation. The REA WG supports the continued policy of self-commitment into the energy market. If an energy must offer requirement is applied to volumes that do not clear in the capacity auction these offer volumes should not be subject to price mitigation. Page 13

14 Market Power Interdependencies Across Working Groups As noted in the Market Mechanics table on page 7, the following interdependencies regarding market power mitigation have been identified to date through the working group process. Please provide your feedback on the best approach for addressing these, and note if there are any additional interdependencies that should be considered. Within a capacity market construct, participant revenue is comprised of energy, ancillary service (AS) and capacity market revenue streams. Together, these are intended to provide incentives for investment and efficient and effective operation of the power system. Market power mitigation within this structure is intended to ensure that participants are not able to behave in such a way so as to sustainably impact price to earn excessive rents from a specific segment of the market (energy, AS, capacity) or between markets, while recognizing that sustainability of the market requires a structure which allows a reasonable opportunity to cover costs, earn returns on capital invested, and provide incentives for the development of competitive advantages. One feedback mechanism built into the market is the concept of net-cone and its potential use within implementing the capacity market such as creation of the demand curve, offer caps in the capacity market or as part of a performance penalty mechanism. The use of net-cone naturally incorporates energy and ancillary market expectations into capacity market considerations. As such, a pertinent question is whether this effectively captures interdependencies between the design streams. With this as a consideration, potential interdependencies regarding approaches to market power mitigation between design streams have been identified as: Description Resource Adequacy Procurement & Hedging Eligibility Market Mechanics Energy & Ancillary Services (EAS) Offer Obligations Must offer obligation in the capacity market, which may be subject to an offer cap. Being awarded a capacity contract creates an obligation for delivery into the energy market. Leading development of amount and type of capacity eligible to participate in the capacity market. Leading offer obligations in the capacity market including must offer, and mitigation screens (e.g. existing assets offer at a fraction of net-cone) as well as considerations of price floors or other offer restrictions. Leading offer obligations in EAS including discussion of whether EAS competitively mitigated (e.g. similar to today with potential changes to price/offer cap and/or control limits) or administratively mitigated (cost based). Ties to questions related to pricing in EAS (price cap, floor, shortage/shortfall pricing). Penalties & Incentives The capacity market performance penalty as defined in capacity contract and measured in the performance period (in RT) needs to ensure incentives for delivery without being excessive, creating risk which cannot be effectively managed and reducing investment. Leading development of penalties and incentives and amount of capacity eligible in the capacity market. Link based on obligation to offer into the capacity market and how much capacity has to be offered (i.e. if must offer for UCAP but then mitigated on cost in the capacity market). Linked based on offer obligations and outage approval (i.e. does an AESO approved outage constitute an exemption for a performance event) as well as energy price levels during capacity performance events. Capacity Asset Size Current dispatch tolerance in the energy market is 5 MW, though units as small as 150 kw receive the pool price. If capacity contract is smaller, will need to evaluate what, if any, changes are required to the energy market. Leading determination of what resources are eligible for the capacity market and minimum size requirements. Link based on potential restrictions on offer block sizes and details of market clearing. Link based on what changes, if any, would be required for smaller units that have a capacity contract. Demand Curve The steepness of the demand curve impacts the ability for and impact of the exercise of market power. Leading the development of the demand curve shape. Link based on what resources are eligible for the capacity market. Link based on auction format and market clearing mechanism. See comments below on net-cone. Page 14

15 Description Resource Adequacy Procurement & Hedging Eligibility Market Mechanics Energy & Ancillary Services (EAS) Market Size & Concentration Market size and concentration could have an impact on the amount and types of mitigation measures employed in the capacity and EAS markets. Leading determination of selfsupply options which can impact the size of the market. Link based on what resources are eligible for the capacity market and the amount of capacity they are eligible to participate with. If market is less concentrated may not need as many mitigation screens. If market is less concentrated may not need as many mitigation screens. Net-CONE Intended to ensure sufficient revenue between markets without paying for products twice. Leading the development of CONE and net-cone determination. Key question will be how net-cone is determined. Link based on potential application in performance penalties. Link based on potential use in establishing offer caps. Link as the design of the EAS determines the expected margins to develop the net portion of net-cone. Feedback: The REA WG agrees that there are significant market power interdependencies across the various design streams. The REA WG is concerned that the combination of market power mechanisms recommended in SAM 1.0 will interfere with the market s ability to attract sufficient investment in new capacity as the degree of market power mitigation will prevent new entrants from recovering their costs and from managing their risks. The REA WG recognizes that market mitigation measures are required but does not support the implementation of market power mitigation mechanisms without a clear understanding of the market power issue that the mitigation is intended to resolve. There seems to excessive market mitigation mechanisms with no rationale for their need. The REA WG does not feel the majority of these mechanisms are necessary in the initial implementation of the market, and as the AESO and Government of Alberta have both stated that the initial structure will not be perfect and will change and evolve as we move forward. This is obviously a very interdependent element, but in the end we could be creating an initial structure that is so mitigated that it will inhibit the ability of investors to recover their costs and manage their risks. Which is not great for the attractiveness of the market to investment. Therefore, if market participants can demonstrate that their costs exceed the cap on the demand curve, they should be able to offer at the higher price. Further participants require flexibility to remove capacity from the auction, particularly if penalties can exceed capacity payments. In addition, market participants with no or limited ability to profitably increase capacity prices based on the size of their portfolio and the slope of the demand curve should not be mitigated. the REA WG therefore opposes the imposition of an offer cap on existing capacity resources. The REA WG understands that the Energy & AS work group has concluded that self-commitment can continue. The REA WG supports this conclusion but submits that the real-time energy market requires sufficient flexibility for market participants to manage unit commitment risks associated with a self-commitment model. Market participants require the ability to reflect the related risks and costs in their energy offers. Cost based offers, are too restrictive, and will inherently reduce the ability of market participants to manage risks and recover all costs. If market participants do not have market power, there is no need to impose administrative and restrictive limits on their offers. Therefore, the REA WG recommends that only those market participants that fail a market screen, and their offers have a clear impact on price outcomes should face any form of mitigation. The REA WG believes that some form of scarcity and/or a shortage pricing mechanism is necessary to provide a appropriate price signal to generators, loads and imports during times of supply shortfall. In summary, the REA WG supports an ex-post approach to market power mitigation in the capacity market that reflect the reality of both new and existing capacity resource costs. With respect to the energy market, The REA WG supports the use of an ex-ante approach to market power that is based on transparent requirements for energy offers. Ex-ante market power mitigation should only apply to market participants that exercise market power in a manner that increases price above competitive market outcomes. Page 15

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