California ISO. Issue Paper. Renewable Integration: Market and Product Review Phase 1

Transcription

1 Issue Paper Renewable Integration: Market and Product Review Phase 1 September 30, 2010

2 Issue Paper Phase 1 Table of Contents 1 Introduction and Overview Themes from the Issues Forum and Proposed Schedule Key Stakeholder Themes Stakeholder Comments on Prioritization Principles for ISO Decisions Components and Schedule Objectives of Phase 1 Proposal Next Steps Energy Market Design Reforms Increase Operational Flexibility by Reducing Generation Self-Schedules Economic Dispatch of Variable Energy Resources and the PIRP Changes to the Energy Bid Floor Day-Ahead Scheduling of Renewables and Energy Market Performance Other day-ahead market changes evaluated but considered outside the scope of this initiative (for ) Ancillary Service Market Reforms Finalize Design of Regulation Energy Management Other Phase 1 Activities Related to Ancillary Services Allocation of Renewable Integration Costs Current allocation of integration costs to variable energy resources Background on the dynamic transfers initiative Stakeholder comments on Cost Allocation Research Agenda and Design Options Topics Deferred to Subsequent Phases New Ancillary Service Products and Pricing Mechanisms Impacts of Changes in Wholesale Market Revenues due to Renewable Resources Intra-hour scheduling for VERs and the interties Additional Intra-day Market Settlements CAISO/M&ID Page 2 September 30, 2010

3 1 Introduction and Overview California is a leader in the production of renewable energy, with over 15 percent of energy to serve load provided by renewable resources in The California ISO, state regulators and market participants have also developed innovative mechanisms to support the integration of renewable energy production into system operations and wholesale markets, including most notably the improved wind forecasting and scheduling practices established under the Participating Intermittent Resource Program (PIRP). 2 To date, these mechanisms along with the dispatch flexibility offered by the ISO s wholesale markets have been sufficient to integrate renewable energy with minimal curtailments and with no other significant adjustments to system operations and market processes. However, studies of operational requirements, including the ISO s recent studies of 20% RPS (henceforth 20% RPS Study) and 33% RPS, suggest that the transition to higher levels of renewable energy production, largely from variable energy resources, such as wind and solar, will have increasingly significant impacts on both system operations and wholesale market functioning. 3 This Issue Paper proposes a phased approach to addressing reforms to California ISO market design and market procedures identified as needed to support integration of variable energy resources. 4 The key operational characteristics of such resources are the variability of their fuel sources and the uncertainty associated with forecasting their production. As such, integration of variable energy resources will require increased operating flexibility additional range and speed of operational ramps, notably for load-following, 5 and additional and possibly faster response ancillary service capability from both generation and non-generation resources. There may also be higher frequency and magnitude of over-generation conditions. In addition to providing additional and possibly faster ramps, the existing and planned generation fleet will also likely need to operate at lower minimum loads and provide more frequent starts, stops and additional cycling over the operating day. At the same time, energy market revenues for conventional resources may decline as renewable energy offered at zero or negative prices displaces energy from gas-fired resources and imports. The objectives of this paper are to identify and provide justification for an initial set of priority market design topics and to present design options for those topics. On July 8, the ISO issued a discussion paper that surveyed possible reforms to energy and ancillary service market rules and settlement procedures. 6 On July 16, the ISO conducted an issues forum that elicited stakeholder perspectives on the key market design and scheduling issues, including both verbal 1 CPUC, Renewables Portfolio Standard, Quarterly Report (3 rd Quarter 2010), at p. 2, available at 2 For the current status of PIRP issues, see 3 California ISO, Integration of Renewable Resources: Operational Requirements and Generation Fleet Capability at 20% RPS (August 31, 2010), [henceforth 20% RPS Study], available at 4 Variable energy resources is the term being used by the Federal Energy Regulatory Commission to describe renewable resources that have variable or intermittent production. Variable energy resources is thus used here as an equivalent term to intermittent resources. Not all renewable resources eligible under renewable portfolio standards are variable energy resources. For example, geothermal, biogas and biomass resources generally follow fixed hourly schedules. 5 Load following is used here to refer to the net load shape resulting when variable generation production is subtracted from load. 6 Available at CAISO/M&ID Page 3 September 30, 2010

4 and written recommendations on priority topics. 7 This paper largely reflects these stakeholder views, including the alternative views presented on the market design options, as well as the updated information on operational needs and market impacts resulting from the 20% RPS Study (and interim results from the simulations of 33% RPS). 8 As discussed below, the topics proposed build on the findings and recommendations of those studies. Another consideration is that the Federal Energy Regulatory Commission (FERC) may issue a notice of proposed rulemaking (NOPR) on integration of variable energy resources in the time-frame of this initiative. Most of the issues that could be addressed in the NOPR were presented in FERC s Notice of Inquiry (NOI) on Integration of Variable Energy Resources issued on January 21, The ISO raised some of the proposed topics in this initiative in its comments responding to the NOI. 10 If and when FERC issues a NOPR, the ISO and stakeholders will have to examine whether and how to modify any draft rules under development in this initiative. Based on these inputs and considerations, the following topics are proposed for the Phase 1 of this initiative and certain related ISO initiatives, with development of final proposal on these topics targeted for submission to the Board of Governors in the Spring of 2011: (1) Market rule changes to support continued efficient performance of the energy markets: (a) options for reducing the prevalence of self-scheduling of resources that, if they were bid into the ISO markets, would provide needed operational capabilities for integration of variable energy resources, (b) reforms to the current market rules, including the Participating Intermittent Resource Program (PIRP), to improve participation by variable energy resources in economic dispatch and possibly ancillary service markets, (c) reforms to related market rules, such as the Energy bid floor, and (d) possible changes to the dissemination of wind and solar forecast data to allow for improved performance of the day-ahead markets (to be conducted in the Phase 3 data release initiative). 11 (2) Selected market rule changes to support ancillary service procurement: (a) Implementation of Regulation Energy Management to facilitate participation in the Regulation market by non-generation resources. In addition, the ISO proposes to begin detailed analysis of a third topic in Phase 1: the allocation of renewable integration costs (defined as ancillary service costs and imbalance energy costs) to internal and external (dynamically transferred) variable energy resources, including consideration of any changes to the existing market rules to improve incentives for 7 The stakeholder presentation is available at Stakeholder comments submitted after the stakeholder forum can be found at 8 The ISO held a stakeholder meeting to discuss the findings of the 20% RPS study on September 17, 2010; the presentation is available at The ISO has requested comments on the study methodology and results by October 8, Where relevant those comments will also inform this market and product review. 9 FERC, Integration of Variable Energy Resources,130 FERC 61,053 (Docket No. RM ); 18 CFR Chapter I. Available at 10 See 11 See CAISO/M&ID Page 4 September 30, 2010

5 dispatch and market participation by such resources. This topic would not be completed by Spring of 2011, but decisions on scope could be made by then and a scheduled defined for subsequent completion. Subsequent phases of this initiative, which will begin after the proposed measures for Phase 1 are completed, will address additional topics, which could include further analysis of the need for additional types of ancillary services, the wholesale market revenue impacts of substantial increases in renewable energy production, intra-hour scheduling of internal variable energy resources and the interties, and additional intra-day market settlements. The remainder of this paper is organized as follows. Section 2 provides background, including the general themes presented at the issues forum, and the proposed schedule. Section 3 focuses on reforms related to scheduling, bidding and settlements under the Participating Intermittent Resources Program (PIRP) and in the Energy markets generally. Section 4 reviews implementation of Regulation Energy Management as an initial component of ancillary service market reforms. Section 5 examines the allocation of integration costs, including ancillary service costs, to variable energy resources internal and external to the ISO Balancing Authority Area (BAA). Section 6 discusses the other issues raised by the ISO or stakeholders that might be examined in subsequent phases of this initiative. The issues outlined in this paper will be discussed at a stakeholder meeting on October 5, Themes from the Issues Forum and Proposed Schedule The ISO is appreciative of the participation of the panelists and other participants at the issues forum on July 16. A range of possible market design and scheduling changes were discussed, but generally with an emphasis on being careful in the near term with the scope of any such changes while there is additional clarification of the operational requirements of renewable integration. With the issuance of the 20% RPS Study, the ISO believes that it has taken a significant step forward in clarifying likely operational needs on the system over the next 2-3 years, but recognizes that more analysis needs to be done. 2.1 Key Stakeholder Themes Some of the key themes from the issues forum and subsequent comments were as follows: More experience is needed with the current market design, and planned enhancements, at higher levels of renewable energy production before concluding that additional products or pricing algorithms are needed. 12 When such additional market product needs are clearly identified, the ISO was urged, on the one hand, to evaluate new approaches to product definition and pricing for ancillary services that could better address the time-frames of supply variability; 13 but on the other hand to look first at enhancements to the existing market functionality and to consider whether 12 See comments by Calpine, CDWR, CMUA, CPUC, and SDG&E. 13 See, e.g., comments by CalWEA. CAISO/M&ID Page 5 September 30, 2010

6 reliance on additional procurement of the existing ancillary services operating reserves and regulation would suffice. 14 There were significant disagreements over whether and how to modify the PIRP, or more generally to change allocation of integration costs, to support additional incentives for variable energy resources to participate in the markets. Improvements in inter-regional integration of renewable resources, including through dynamic transfers and through intra-hour scheduling of static import schedules, are needed to support increased renewable imports. Additional specific stakeholder comments will be reviewed in the sections on particular topics below. 2.2 Stakeholder Comments on Prioritization A number of stakeholder comments proposed specific approaches to the phasing of this initiative. Because different comments used different criteria, these are grouped below in roughly the order of priority and general time-frames, with identification of certain stakeholder comments as references. Some useful organizational themes were proposed by several commenters, including CPUC, PGE and SCE. For example, PGE suggested two parallel tracks: Track 1: Operational studies Determination of new market product needs over time Track 2: Market rule changes to existing products and functionality PGE notes that Track 2 would be less dependent on study results and could proceed independently. Several other commenters suggested something similar to a Track 1 process. The ISO generally agrees with this recommendation, and has restructured the process to include meetings on the operational studies as results are available. To summarize the many recommendations on prioritization, the topics labeled below as Initial Phases generally include items that do not require major market rule changes or reliance on new technology. The topics labeled Second or Third Phases require more significant investment in changing market functions by the ISO and market participants as well as likelihood of implementation challenges. The ISO recognizes that this prioritization could change with further operational study results. Initial Phases Completion of operational studies as a precursor to market design changes (CPUC, PG&E, SCE); identification of trajectory of needed changes over the coming decade based on study results (CPUC, SCE) Improved incentives for accurate forecasting (Iberdrola) Increased intra-hour scheduling flexibility, including dynamic scheduling (Iberdrola) Changes as needed to procurement of existing ancillary services, including possible changes in the requirements for the current ancillary services products or how the requirements are calculated, changes to the contingency flag to an hourly designation, preventing non-contingent ancillary services from being converted to contingent in realtime in which incremental reserves are procured to maintain flexibility of a non- 14 See, e.g., comments by Calpine. CAISO/M&ID Page 6 September 30, 2010

7 contingent designation, 15 setting the real-time ancillary services forecast as a function of a more recent load forecast (PG&E) Completion of all outstanding issues related to mandates and operational requirements that would affect existing PPAs as well as new ones (WPTF); to the extent they are not already settled, these would include requirements for low voltage ride-through, dispatchability, inertial response, and meteorological data and any related equipment or options (WPTF) Changes to bid floor (PG&E) Subsequent Phases Variable energy resource curtailment methods, such as changes to PIRP (Iberdrola, PG&E) Renewable integration cost allocation issues (PG&E, WPTF) Market scheduling changes that improve renewable integration (WPTF) Determination of need for new market products (PG&E) Incentives for storage technology to provide integration services (Iberdrola) 2.3 Principles for ISO Decisions A key principle that the ISO will follow in this initiative is to focus on adjustments to existing market products and processes as far as possible in the early phases, and to provide sufficient time to analyze and review with stakeholders any proposed new market products or other significant changes to market design. The ISO generally agrees with stakeholders that the market and system operational capabilities inherent in the current market design will be particularly useful in the next decade given that renewable integration will likely become the major driver of operational needs on the power system. Planned enhancements to the ISO markets in particularly convergence bidding, scarcity pricing of ancillary services, additional bidding flexibility for multi-stage generation, and rules to facilitate ancillary service provision by non-generation resources will provide additional benefits for variable energy resource integration and improve overall market performance as the amount of variable energy resources increases. A second principle is that the ISO will address a limited number of issues for Board approval initially, recognizing that the operational studies will provide substantial results for consideration over the remainder of 2010 and early However, as discussed in more detail below, operational studies suggest that additional market design and procedure changes will be needed at around the 20 percent RPS level, and soon after, and hence a timely start to consideration of those changes is warranted. Given these guiding principles, the ISO believes that the proposal for Phase 1 is largely consistent with stakeholder views and with market needs reflected in the 20% RPS Study. 15 This option is already in the ISO roadmap, see CAISO/M&ID Page 7 September 30, 2010

8 2.4 Components and Schedule Objectives of Phase 1 Proposal Item Refinements to improve operational flexibility of existing fleet measures to reduce generation self-schedules Reforms to support economic dispatch of renewable resources Reforms to PIRP rules Revision to bid floor Schedule Final Proposal to BOG, Spring 2011 Final Proposal to BOG, Spring 2011 Changes to rules for dissemination of VER forecast data to assist day-ahead market functioning Implementation of rules for Regulation Energy Management Evaluation of changes to allocation of renewable integration costs Determination of Phase 2 topics and schedule (2011) For consideration in Phase 3 of the data release initiative Final Proposal to BOG, Spring 2011 Detailed review completed by Spring 2011 Detailed review with stakeholder input and recommendations by Spring 2011 Item Date Publish Discussion Paper July 8, 2010 Stakeholder Forum July 16, 2010 Stakeholder Written Comments Due July 30, 2010 Publish Phase 1 Scope and Issue Paper September 28, 2010 Stakeholder Meeting October 5, 2010 Stakeholder Comments October 18, 2010 Publish Phase 1 Straw Proposal December 1, 2010 Stakeholder Meeting December 8, 2010 Stakeholder Comments Late December Publish Phase 1 Draft Final Proposal Q Board of Governors Meeting Phase 1 Spring 2011 CAISO/M&ID Page 8 September 30, 2010

9 2.5 Next Steps The ISO will hold a stakeholder meeting on October 5, The ISO seeks stakeholder written comments following the phone call by October 18, Please all correspondence to RI-MPR@caiso.com 3 Energy Market Design Reforms The increase in renewable energy production over the coming years, with an increasing proportion from variable energy resources, will have a number of impacts on the day-ahead and real-time energy markets. Some key observations and findings from ISO analyses, including notably the 20% RPS Study, include the following: Real-time load-following 16 requirements capacity and ramp rates will be increasing with the addition of wind and solar resources [20% RPS Study, Section 3]. The historical real-time ISO commitment and dispatch has provided some additional load-following capability that could support integration of additional variable energy resources over the next 2-3 years without further changes to market design (i.e., prior to the ISO having to augment load-following capability by changes to unit commitment algorithms and possibly additional load-following reserves). However, at least in the downwards direction, much of that capability is limited by self-schedules, particularly in certain hours [20% RPS Study, Section 4]. In addition, while load-following up is generally less of a concern than load-following down in the next 2-3 years, the real-time dispatch is currently persistently constrained in the upwards direction in certain hours due to ramp constraints and local congestion, as indicated by real-time prices above the bid cap [see Table 1, below]. Overgeneration is likely to increase in frequency and magnitude at higher levels of renewable production [20% RPS Study, Section 5]. Both simulations and the historical experience as reflected in the frequency of negative real-time prices [20% RPS Study, Table 4.1, pg. 69], confirm that such system conditions will be prevalent in the Spring months. 17 Zero or negative prices will be particularly prevalent when decremental energy 16 There are several ways to define load-following requirements. Load-following is conducted by resources on real-time economic dispatch. One measure of changes in load-following requirements is the change in the ramp-rate and the duration of the ramp-rate in various load-following time-frames (e.g., 1-minute, 5-minutes, 10-minutes). Another measure is the load-following capacity, defined here as the difference between the maximum 5-minute dispatch energy requirements in the upward and downward directions and the hourly schedule going into the operating hour. For further discussion, see the 20% RPS Study. 17 During extreme over-generation conditions, controllable generation and imports are at their minimum levels or are shut down, exports are maximized and the total net generation production still exceeds the system load. As such, the real-time energy prices typically go negative and the ISO, at times, literally pays adjacent balancing authorities to take the excess energy. Negative real-time energy prices are CAISO/M&ID Page 9 September 30, 2010

10 bids are thin, i.e., in periods of off-peak overgeneration or when high renewable energy production requires self-schedules of other generation resources to be violated, which could include morning and evening ramp periods at higher levels of renewable production [20% RPS Study, Sections 4-5]. Since variable energy resources currently do not bid into the day-ahead market (in accordance with the current provisions of the PIRP), day-ahead and real-time prices will systematically diverge unless there are sufficient incentives for these resources to participate in the day-ahead market or for other entities (e.g., virtual bidders) to take dayahead positions that reflect expected renewable energy production in real time. Day-ahead wind forecast errors, while potentially leading to inefficient unit commitment, do not appear to create problems for real-time system operations in sequential production simulations that considered forecast uncertainty at 20% RPS [20% Study, Section 5]. Aggregate energy market revenues for gas generation will likely decline due both to displacement of gas production by renewable energy and lower prices for energy 18 [20% RPS Study, Section 5] These operational requirements and market impacts have raised several fundamental policy and market design questions: How can California ensure that its existing dispatchable generation fleet remains available and is effectively utilized to achieve maximum renewable integration with minimal disruption to wholesale market functioning? How can variable energy resources participate more effectively in the energy markets on an economic bid basis and actively manage their power production to participate in efficient management of overgeneration, congestion and at times also extreme system ramps? An initial set of proposed measures to address these questions is presented in the remainder of this section. 3.1 Increase Operational Flexibility by Reducing Generation Self-Schedules The ISO anticipates that for much of the coming decade, most of the needed operational flexibility to support renewable integration will need to come from dispatchable thermal and hydro generation along with pumped storage, although with an increasing contribution over time from newer types of non-generation resources such as advanced storage and demand intended to provide the appropriate economic signals for supply resources to economically curtail their production, at these times; a question discussed later in this paper is whether the energy bid floor is sufficiently low to allow market participants to bit their true willingness to curtail. to provide incentives for curtailments. 18 Renewable resources sell their energy on a forward basis through bilateral contracts and typically schedule the resulting energy production without a bid. As a result, their energy is seen from a market perspective as having essentially a zero price or less than zero (negative) price if they submit a bid that reflects their lost opportunity costs, including production tax credits. CAISO/M&ID Page 10 September 30, 2010

11 response. Prior to procuring additional or new types of reserves or making further adaptations of unit commitment algorithms to address ramp constraints, the ISO believes that the policy objective should be to remove barriers to achieving maximum operational flexibility under the current market design. Generation resources (and load) participate in the ISO markets in essentially two ways: economic bids to provide specified quantities of energy and ancillary services at specified prices; and self-schedules, which are requests to the ISO to operate a generator at a fixed output over the hour or to accept specified amounts of self-provided ancillary services. Economic bids allow the ISO full flexibility to optimize the use of the resource over the range of output being offered and the existing grid conditions at the time the market runs. Self-schedules limit this flexibility and can result in highly inefficient market solutions. SCs may choose to submit self-schedules based on various factors, including physical or environmental operating constraints that the resource operator does not want the ISO to violate, bi-lateral contractual arrangements including forward contracts, and ISO market rules and incentives. As noted, a key finding from the 20% RPS Study is that self-scheduling is a significant barrier to efficient renewable integration. From April 1, 2009 to the end of 2009, self-scheduling accounted for 70-80% of the day-ahead market volume, depending on the month, and analysis of trends in self-scheduling in 2009 have not shown any decrease in this practice. 19 Selfscheduling already leads to inefficiencies in the economic dispatch, which could only be exacerbated by the additional load-following needed and the expected increase in overgeneration associated with renewable integration. 20 While the statistical simulations conducted by the ISO for the 20% RPS Study suggest increases in load-following requirements, it is more complicated to evaluate precisely how those additional requirements would be affected by the current constraints on dispatchability due to self-schedules. To gain some perspective, the ISO conducted analysis of the historical dispatch from April 1, 2009 to June 30, 2010 and determined that the 5-minute load following upwards capability appears sufficient to cover the additional requirements simulated under a 20% RPS in most intervals (but assuming that the simulated requirements are reached not much earlier than 20 minutes into the hour). However, real-time prices greater than the bid cap, as shown in Table 1 below, already give some indication that upwards ramp constraints are being violated in some hours, and this may increase with higher load-following requirements without the consideration of either changes to unit commitment algorithms or new products. The more severe near-term problem appears to be with downward dispatchability, which is currently significantly limited by self-schedules in some hours, such that the additional load-following down requirements would begin to lead to non-economic curtailment of self-schedules. The two figures below compare the calculated summer season 5-minute load-following down capability limited and not limited by self-schedules. 21 Figure 1 shows the downward capability of thermal units assuming that self-scheduled units cannot be backed down below the 19 California ISO, Annual Report on Market Issues and Performance, 2009 (April 2010), pg. 3.8; available at The monthly trends are shown in Figure 3-6 on pg See ibid., pg. 3-8: Under the new market design, extremely high levels of self-scheduled supply can decrease market efficiency by reducing the degree to which the market software is free to optimize different supply resources based on their bid costs. High levels of self-scheduled supply can also hinder the ability to manage congestion in the most cost-effective manner. 21 The calculation is based on a unit s downward capability times the lower of its self-schedule or its lower limit, a 5-minute ramp constrained value calculated by the system software. CAISO/M&ID Page 11 September 30, 2010

12 level indicated in the self-schedule. Figure 2 shows that when this constraint is ignored, current load following down capability could more than double in many hours if all thermal generation were fully dispatchable. The analysis of the other seasons is available in the 20% RPS Study and shows similar relationships. 22 In addition, Table 4-1 in the 20% RPS Study shows the number of 5-minute intervals with negative prices by hour of day and season from April 1, 2009 to June 30, 2010, showing the number of instances in which downward dispatch was constrained by self-schedules, ramp limits, or overgeneration conditions. That table shows that downwards capability is more constrained in the Spring and early summer (June) months. Figure 1: Summer 5-Min Load-following Down Capability (Limited by Self Schedules): June 2009-August 2009, June 2010 Figure 2: Summer 5-Minute Load-following Down Capability (not limited by Self- Schedules): June 2009-August 2009, June 2010 In some hours, this lack of dispatchability despite the physical availability of loadfollowing capability could lead to ISO dispatchers needing to rely on Exceptional Dispatches to 22 Integration of Renewable Resources, located at pgs viii-ix. CAISO/M&ID Page 12 September 30, 2010

13 access the available ramp capability on the system for renewable integration. The result would be distortion of market prices and an increase in Exceptional Dispatches. The adverse impact of self-scheduling on the ISO s load-following capability could be reduced in essentially four ways, which are not necessarily mutually exclusive: 1. An increase over time in the voluntary submission of market bids due to the increased incidence of more extreme prices (positive and negative) in real-time, 2. Market procurement of additional reserves to provide load-following, 3. Changes to unit commitment algorithms to ensure adequate dispatchable ramp capability in intervals with high upward and downward ramp requirements, and 4. Administrative changes to market rules to require submission of economic bids by some or all classes of resources, particularly Resource Adequacy resources that already have a must-offer obligation. Turning to the first component, economic bids would be expected to increase in volume if the increase in extreme negative or positive prices (depending on whether the ramp constraints being violated are downwards or upwards, respectively) in real-time intervals causes suppliers to provide more dispatchability, to earn higher revenues from the higher prices for incremental dispatch or the negative prices for decremental dispatch below their day-ahead schedules, or to avoid paying negative prices. Currently, the negative prices are limited by an offer floor, but that could be changed as well, as discussed below. If the ISO and stakeholders feel that this market adjustment will take place efficiently, then any further changes in market design would be contingent in part on evidence that the actual load-following capability of dispatchable resources under the current market design has been exhausted and requires additional measures. The second component of the market design would then be to procure additional, noncontingent reserves to cover load-following requirements, but the ISO believes that new products should only be implemented after other measures have been undertaken to increase dispatchability. As a third component, the ISO could also change its unit commitment algorithms to further position dispatchable resources with high ramp rates in hours that have high ramp requirements. The fourth type of measure, administrative rule changes to require submission of economic bids, is a more significant departure from the current market design philosophy. This approach could be justified if, on the one hand, real-time prices are reflecting the increasing impact of significant ramp constraints, but on the other hand, there is no decrease in selfscheduling. That is, voluntary market adjustments do not take place sufficiently in advance of the operational need, leading to increasingly volatile real-time pricing. As noted above, at least the first 9 months of the redesigned market did not appear to significantly alter the percentage of self-scheduling, and the ISO continues to survey the months of This outcome would threaten the ISO s ability to integrate renewable resources. The ISO therefore asks stakeholders to consider whether, and if so, when such administrative rule changes that would reduce self-scheduling would be appropriate including quantitative triggers, such as the frequency of negative and positive extreme prices. The ISO stresses that even with such a rule, market prices for energy and ancillary services would still establish the value of operational capabilities. To further explore this question, the ISO would suggest that a natural starting point is to consider changes to the must-offer requirements for certain types of both use-limited and non- CAISO/M&ID Page 13 September 30, 2010

14 use-limited Resource Adequacy (RA) resources as contained in section 40 of the ISO Tariff (changes to the rules for variable energy resources are discussed in the next section). These changes would reflect the constraints on dispatchability inherent in different unit types. The objective is to begin to adapt the rules for RA resources to reflect the changing operational conditions on the grid. The ISO seeks input from stakeholders and the CPUC to provide further definition to such rule changes.the ISO recognizes that non-ra resources also have the option to self-schedule, and hence that imposing new bidding requirements on RA resources that are not equally imposed on non-ra resources requires justification. At the same time, non-ra resources do not have any obligations to bid into the ISO markets unless they are designated under ICPM or an RMR contract. Moreover, while there have been discussions of adding operational characteristics such as dispatchability to the RA program requirements, such changes have not yet been initiated. Hence, the primary justification for the suggestion in this paper is clearly that only RA resources already have must offer requirements for their RA capacity, and concurrently, that the ISO markets can compensate those resources through the specifications in their bids for the costs of operating to provide integration services, such as ramping, ancillary services, and decremental dispatch below their IFM schedules. CAISO/M&ID Page 14 September 30, 2010

15 Table 1: Number of Real-Time Dispatch Intervals with Prices Bid Cap by Month and Hour, April 1, 2009 to June 30, Apr (Out of 360int/ hr) May (Out of 372int/ hr) Jun (Out of 360int/ hr) Jul (Out of 372int/ hr) Aug (Out of 372int/ hr) Sep (Out of 360int/ hr) Oct (Out of 372int/ hr) Nov (Out of 360int/ hr) Dec (Out of 372int/ hr) Jan (Out of 372int/ hr) Feb (Out of 336int/ hr) Mar (Out of 372int/ hr) Apr (Out of 360int/ hr) May (Out of 372int/ hr) Jun (Out of 360int/ hr)

16 3.2 Economic Dispatch of Variable Energy Resources and the PIRP Another element of this initiative (but one that could overlap with the examination of selfscheduling rules discussed above) will be to consider the impact of the PIRP rules and the bid floor of -$30/MWh on the incentives, and ability, of wind and solar resources to offer economic bids. If the ISO seeks to increase the incentives for these resources to offer economic bids, or create administrative requirements to do so, then both of these features of the current market design must be reevaluated for the disincentives they create. For example, if (decremental) bidding by renewable resources becomes mandatory, as offered for consideration in the previous section, then the ISO will have to consider associated rule changes to relieve PIRP participants of the requirement to self-schedule in the RTM and to reduce the bid floor to allow certain renewable resources to bid to at least cover their opportunity costs, as reflected in, e.g., production tax credits. The ISO believes that a thorough reevaluation of the PIRP is unavoidable. The PIRP was designed and implemented well before there was a clear expectation of the enormous growth of variable renewable resources that will occur under higher RPS and without the benefit of what we have learned from the studies of the operational impacts of renewable integration. As such the PIRP contains no provisions for real-time re-dispatchability of these resources through the RTM. As discussed in the 20% RPS Study, operational conditions that could require curtailment of renewable energy are expected to increase in frequency and magnitude, particularly overgeneration in Spring high hydro, light load conditions, but over time also during some daily ramp intervals, depending on how other resources on the system are scheduled and bid. While the ISO could continue to send dispatch instructions to variable energy resources only on a noneconomic reliability basis, price-based (economic) dispatch of such resources is necessary for efficient management of system constraints and thus actually benefits renewable energy production. Under economic dispatch, the operator of a variable energy resource can generally know that only the MW specified by the RTM dispatch are required to be curtailed and that the RTM will determine an efficient bid-based price for settling such curtailment. For these reasons, as shown in Table 1, several eastern ISOs and RTOs have moved recently to require submission of economic bids by wind resources to improve congestion management (when wind production is contributing to congestion), as well as to mitigate overgeneration. The ISO would like stakeholders to consider all options to encourage economic dispatch of variable energy resources with a view to maintaining the ability of the ISO markets to manage system operations efficiently. The current PIRP rules will need to be examined in the context of this effort at economic dispatch. At the very least, if the PIRP financial settlement rules are retained, the rules are likely to need modification to allow submission of economic bids without loss of the settlement benefit. Alternatively, the ISO and stakeholders may consider that PIRP financial settlement rules need modification in themselves. Before describing the options, the next section provides some background on PIRP Background on PIRP Rules Reflecting stakeholder views, the ISO emphasizes that any changes to the PIRP will be considered carefully and with due respect given to the important role that PIRP has played in the development of the California renewable industry. In the early 2000s, the financial risk of

17 being exposed to the wholesale market costs of energy imbalances 23 was seen as a significant impediment to wind resource development. In July 2001, with support from the utilities and state agencies, the ISO instituted a stakeholder process to develop PIRP that resulted in a consensus proposal and Board approval in September The rules for the PIRP were approved by FERC in 2002 and implemented in June With the advent of the redesigned market in April 2009, the PIRP rules were changed again to be compatible with the new ISO market structure, both to remove some charge types and to reflect settlements at locational marginal prices. Under the current PIRP rules, the participants receive several benefits. Program participants are exempt from or receive special treatment for several of the market charges. Deviations are netted over the month for market settlement. 25 In exchange for these benefits, the Program participants are required to sign ISO agreements, install ISO meters, provide telemetry of data, report outages, pay a forecast fee of 10 cents per MWh, and self-schedule in the RTM consistent with the ISO s forecast of wind generation. 26 AWS Truepower is the vendor supplying the forecast. Balancing these benefits to the Program participants are the costs imposed on the other market participants who pay for the benefits received by the Program participants. As Imbalance Energy is procured on a five-minute basis and settled on a ten-minute interval basis, assessment of monthly netting of deviations may not recover the payments for Imbalance Energy. Typically, there is a shortfall in revenue because the revenue from monthly netting is less than the payments for Imbalance Energy. This shortfall is assessed to market participants (including participating intermittent resources) through an assessment on Net Negative Deviations. Program participants are also exempt from paying uplift to cover Minimum Load Compensation Costs. 23 Because of the variability of wind, and to some degree, solar generation, these renewable resources experience significant differences between their scheduled and actual output, called an imbalance. For example, based on its hour-ahead forecast, a wind farm with 120 MW of capacity could schedule to produce 100 MW over the hour between 8 am and 9 am, but then actually produce in a range between 50 MW and 120 MW in any particular 5-minute dispatch interval during the hour. When a wind resource is producing below its scheduled output, the ISO has to increase the output of other generation for that period; and when it is producing more than its scheduled output, the ISO may have to back down some other generation, which may also incur costs if that generation has already been paid for its output in the day-ahead market. 24 The development of PIRP was a collective effort under a working group that consisted of representatives of the ISO, the State of California, wind power associations, wind power operators, generators, investor owned and municipal utilities, the forecasting vendor and consultants. 25 Both the locational marginal price and the MW deviations from the schedule are averaged over the month. 26 In October 2009, the ISO Board of Governors approved two further changes intended to promote more accurate intermittent resource forecasts: (1) extending the obligation to install specified forecasting and telemetry equipment and communicate relevant data to the ISO from Participating Intermittent Resources (PIR) to all interconnecting Eligible Intermittent Resources (EIR) with a Participating Generator Agreement (PGA) or Qualifying Facility Participating Generator Agreement (QF PGA), unless otherwise exempted; (2) reducing the threshold for reporting a Forced Outage at an EIR with either a PGA or QF PGA from the current 10 MW level to 1 MW. However, the obligation for all Generating Units, including EIRs, to explain the Forced Outage will continue to apply only to Forced Outages of 40 MW or more. CAISO/M&ID Page 17 September 30, 2010

18 To be eligible for the PIRP settlement, participating resources are not allowed to submit economic bids into the energy and ancillary service markets. If a participating resource chooses to participate in a particular hour, the PIRP program requires that the facility self-schedule into the real-time market, utilizing the hourly forecast provided by the independent forecast vendor. The scheduling coordinator representing the PIRP resource must use the hour-ahead forecast that is available 30 minutes prior to the deadline of the bid-submission process for the real-time market. If the ISO fails to provide the forecast prior to 15 minutes before the deadline, the PIRP resource must use their most recent energy forecast provided. Adherence to the scheduling rules above is required to include that hour s production in the settlement which calculates deviations as the weighted average of LMPs multiplied by the net imbalance deviations over the month. The result to date is a small subsidy to the wind resources from the buyers in the realtime wholesale market (who pay for all real-time energy at its actual cost), and correspondingly typically a small reduction in the financial risk of participation in the market for wind generators. Figure 3 below shows the $/MWh of uninstructed imbalance energy (UIE) charges which are allocated to the market participants net negative deviations. The source data for this chart is available on the ISO website. 27 Typically, the PIRP benefit is $2-$4/MWh. However, as the amount of variable energy resource production on the system increases, the financial implications of the difference between scheduled and actual output could become larger. The subsequent figures aim to provide more context for understanding how the PIRP benefits relate to other factors, such as forecast errors, LMPs and hour of day. Figure 4 shows on a ten-minute basis the average PIRP benefit, the average forecast error, 28 and the average LMP for a particular resource. This figure shows that LMPs are not currently the primary drivers of the PIRP benefits; rather, the major payments are a function largely of the highest forecast errors. That is, PIRP is largely not reducing wind resources exposure to high LMPs, but rather to high forecast errors. Figure 5 clarifies that for all resources, the major PIRP benefits are concentrated in hours 19-24, when wind is ramping up, due to the forecast errors in that period. Interestingly, the same concentration of PIRP benefits is not apparent in the morning hours when wind is ramping down. $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 PIR UIE Charges Allocated to Market per MWh Jan 05 Apr 05 Jul 05 Oct 05 Jan 06 Apr 06 Jul 06 Oct 06 Jan 07 Apr 07 Jul 07 Oct 07 Jan 08 Apr 08 Jul 08 Oct 08 Jan 09 Apr 09 Jul 09 Oct See 28 Measured as the difference between the hour-ahead forecast and actual production. CAISO/M&ID Page 18 September 30, 2010

19 Figure 3: PIRP UIE Charges Allocated to Market per MWh, January December 2009 Cost ($) Average Subsidy Average Forecast Error Average LMP Forecast Error (MW) or LMP ($) Figure 4: Comparison of average PIRP benefit, average forecast error, and average LMP by 10 minute period for one plant, 1/1/10 to 5/31/10 CAISO/M&ID Page 19 September 30, 2010

20 Average Subsidy ($) Hour Figure 5: Average PIRP benefit, all resources, by hour of day, 1/1/10 to 5/31/ Comparison with other ISO and RTO Market Rules While PIRP was an innovation in facilitating the entry of wind resources into ISO markets, most other ISOs and RTOs now have specific rules for participation by wind resources in the economic dispatch that provide system operators with more dispatch flexibility than is afforded to the California ISO. Table 2 compares these rules for both the day-ahead and realtime markets; this section discusses real-time dispatch. 29 In the real-time markets, both PJM and NYISO now require that variable energy resources submit bids to decrement, although with specific provisions for how and when those bids are dispatched. All other ISOs currently require VERs to submit self schedules in real-time based upon the resource s forecasted output. For the NYISO, FERC has approved rules that require intermittent resources to submit (negative) economic bids that reflect their willingness to curtail. These rules also ensure that wind resources are not curtailed if other resources are still available to redispatch. If a wind resource operates above its dispatch level after receiving a curtailment dispatch, it is not paid for the excess generation and is charged an overgeneration penalty comparable to that applied to conventional resources. PJM applies redispatch and curtailment rules comparably across all energy suppliers. PJM treats all resources with identical energy offers the same in its dispatch, regardless of whether they are intermittent resources or conventional generation. PJM also allows all resources to submit negative economic bids, which allows PJM to dispatch those offers during constrained conditions. 29 The data for Table 2 was gathered from the various ISO responses to the FERC NOI on integration of variable energy resources. CAISO/M&ID Page 20 September 30, 2010

21 Table 2 Comparison of ISO rules for scheduling and bidding of variable energy resources Day Ahead Real Time CAISO Optional Self scheduled according to hour-ahead forecast; Decremental bids are voluntary, but result in reduction of PIRP settlement benefits PJM Yes for RA. Incentive to minimize uplift costs Decremental bids are mandatory for capacity resources NYISO Optional Decremental bids are mandatory for capacity resources ISO-NE Optional Self schedule by VER s hourly forecast MISO Yes for RA Self schedule Table 3 compares the differences in treatment of imbalance energy and uplift. 30 Only PJM applies their balancing operating reserve charge (uplift to cover start-up costs and other factors) to deviations from day-ahead schedules. 31 This rule creates an incentive to participate in the day-ahead market to minimize the uplift charges, because a resource that does not have a schedule would have the uplift applied to all energy delivered. However, PJM emphasizes that the uplift charge is very small. In PJM, MISO, and ISO-NE, all resources, including wind energy, receive the real-time LMP for energy delivered and do not apply penalties for deviations from submitted schedules or dispatch instructions. NYISO also settles all resources at the realtime LMP for energy delivered, but applies penalties to resources that do not follow dispatch instruction to curtail. Table 3 Comparison of ISO rules for allocation of uplift and imbalance energy charges Uplift Imbalance Energy CAISO Exempt PIRP rules as described above PJM Apply balancing operating reserve charge (< $1.50 / MWh). Real Time LMP. No penalties for deviations from schedules. NYISO Exempt Real Time LMP, but if instructed to curtail, not paid for excess and pay over generation charge ISO-NE Exempt Real Time LMP, no deviation penalties MISO Exempt from Revenue Sufficiency Charge, but being revisited. Real Time LMP, but exempt from Excessive Deficient Energy Charges 30 The data in Table 3 was gathered from the various ISO responses to the FERC NOI on integration of variable energy resources. 31 See CAISO/M&ID Page 21 September 30, 2010

22 3.2.3 Stakeholder Comments on PIRP Stakeholder comments on PIRP generally addressed the financial settlement aspects of the program, and not the ISO proposals described above in Section 3.1 to require submission of Bids. A number of parties argued that PIRP should remain in place and should not be changed at this time (CPUC, Iberdrola, IEP, Shell). They pointed to PIRP s benefits to variable energy resources, and suggested that it should be refined and enhanced (CalWEA, Shell). Two such proposed enhancements would be to extend the PIRP rules to out-of-state eligible resources that are dynamically scheduled into the ISO (CalWEA, LS Power), and to extend the PIRP rules and forecast to the day-ahead market (CalWEA, Flynn Resources, SDG&E). However, other stakeholders suggested that PIRP participation should not be expanded (SCE, Calpine) and that PIRP should not be extended to the day-ahead market (WPTF). These topics are discussed further in Sections 3.4 and Options for PIRP Reforms There are several options for PIRP reform that the ISO would like stakeholders to consider (including the option not to change any aspect of the current rules). Generally, they fall into two categories: minor changes to the PIRP financial settlement rules to facilitate submission of economic bids, whether through mandatory rules or economic incentives, as discussed above; and more significant changes to the PIRP financial settlement rules that would strengthen incentives to participate in the ISO markets. If the PIRP rules are largely retained, then the ISO believes that at least minimal changes to improve dispatch incentives should be considered. These could include retaining the current PIRP hour-ahead scheduling process and financial settlement rules for any real-time intervals for which the resources have scheduled, but allowing resources to submit economic bids into the energy and ancillary service markets without losing the PIRP settlement for any intervals in which those economic bids aren t selected. That is, if a resource submits an economic bid, and is selected to curtail for some or all dispatch intervals within the operating hour, and follows dispatch instructions, the remaining intervals when the resource is not instructed to decrement below its schedule would continue to be settled according to the current rules. Since the resource is not deviating from schedules when following dispatch instructions, this modification is consistent with market design principles. For example, the SC for a 100 MW unit submits an hour-ahead schedule for 80 MW following the wind forecast. In 5 dispatch intervals within the hour, the unit is dispatched down from its actual production, which is varying between MW in each interval, to 70 MW a curtailment of MW depending on the interval. In those intervals, it is paid its bid to back down. The PIRP financial settlement rules would then apply for all the other intervals in the hour. A more significant change to improve dispatchability incentives would remove PIRP financial settlement rules altogether, potentially for all resources or perhaps only for new wind and solar resources not already in PIRP, and adopt a variant on the eastern ISO/RTO settlement rules surveyed in Table 2. The PIRP hour-ahead (and day-ahead) forecast would remain in place as an advisory schedule, but it would no longer serve the function that it currently does. In this instance, resources would simply be settled for energy production at LMP, rather than at monthly netted deviations and averaged LMPs. All the eastern ISOs and RTOs appear to exempt variable energy resources from any administrative penalties for deviating from prior schedules, although some markets require a day-ahead schedule to be CAISO/M&ID Page 22 September 30, 2010

23 settled at LMP for wind capacity resources and apply uplift charges to deviations from the dayahead schedule. These specific rules would be the subject of the next paper in this initiative, if this option was chosen for further exploration. The advantage of adopting some variant on this approach at this time (prior to the expansion of renewable energy expected in the coming years) is that it provides improved price signals to the resources for redispatch and minimizes the need to rely on administrative (out-ofmarket) instructions to address operational requirements. Finally, as discussed above, other ISOs vary as to whether there is a penalty when variable energy resources do not respond to ISO dispatch instructions. This could be a direct penalty based on the MWh of deviations or it could simply mean applying the actual LMP rather than an averaged financial settlement as under the current PIRP rules. The California ISO does not currently apply a penalty for uninstructed deviations, so this type of policy would require additional changes to the market tariff. The ISO notes that these are options for discussion that are reflective of the rules already approved in other regional markets. The ISO is also seeking comment on any variants in these financial settlement rules that might support the objective of attaining economic dispatch of variable energy resources. 3.3 Changes to the Energy Bid Floor The level of the energy bid floor is a further potential change to market design that has implications for either voluntary or mandatory changes in market scheduling and bidding practices. At its current level of -$30/MWh, the bid floor provides a disincentive for some resources, including resources receiving production tax credits greater than that amount, to provide decremental energy bids. This section first provides background on the bid floor and then examines options for changing it Background A supply resource uses its energy bids for two main purposes in the ISO markets: first, to specify the minimum price at which it is willing to provide energy to the market, and second, to specify the maximum price it is willing to pay to buy back in real time energy it sold in the day-ahead market. Energy bids for the latter purpose are commonly called decremental (or DEC) bids because they are bids by a supplier to reduce or decrement its real-time output relative to its accepted energy schedule. Decremental bids are also the focus of the present initiative, because the integration of large quantities of variable energy resources into the supply fleet creates an increased need for a liquid supply of such bids to manage real-time congestion and over-generation conditions. If there is not a sufficient supply of decremental bids in an overgeneration situation, to maintain system balance the ISO must issue non-economic instructions (i.e., instructions that are not based on energy bids) to resources to reduce their output. For a variety of reasons, these non-economic dispatch instructions result in less efficient use of resources. The ISO therefore aims to have sufficient decremental bids in the real-time market at all times, to manage both over-generation conditions and transmission congestion in the most efficient manner. An indication of the frequency of decremental bid insufficiency is found in Table 4-1 in the 20% RPS Study, which shows the number of 5-minute intervals with negative prices by hour of day and season from April 1, 2009 to June 30, CAISO/M&ID Page 23 September 30, 2010

24 Regardless of which of the two purposes noted above the bid serves, energy bids in the ISO markets must be between the energy bid cap of $750 per MWh 32 and the energy bid floor of negative $30 per MWh (-$30). 33 The energy bid floor is most relevant to the supply of DEC bids, in the sense that the lower parties can bid the more we would expect the supply of DEC bids to increase. Intuitively, a resource that sold 100 MWh of energy at a price of $50 per MWh in the day-ahead market will be more willing to buy it back at a real-time price of $20 (and still earn $30 per MWh on the difference between the two transactions) than at a price of $40 (and earn only $10 per MWh on the transactions). As bids move into the negative realm, buying back at a price of -$20 means that the resource is paid $20 for each MWh that it reduces its output (thus earning a total of $70 per MWh on the two transactions in this example). The above discussion leads to the questions that are the focus of this section of the paper: If the ISO today is experiencing instances of insufficient DEC bids to manage overgeneration, and given the likelihood for over-generation to increase in frequency and magnitude in the future, is the current energy bid floor of -$30 per MWh too high so that it creates a disincentive for resources to offer DEC bids? 34 If so, how should the energy bid floor be changed to elicit sufficient supplies of DEC bids in all hours? The energy bid floor for the ISO s market redesign based on locational marginal pricing was originally proposed in the ISO s 2002 market redesign filing (submitted on May 1, 2002). At that time, the ISO recognized the need to have sufficient DEC bids to manage congestion and overgeneration, and proposed that a bid floor of -$30 per MWh was appropriate. The ISO reasoned that participants could reasonably justify negative energy bids to reflect their willingness to buy back scheduled energy for the following reasons: 1. A generator that reduces generation may face gas imbalance charges if it does not consume gas it has already nominated to flow; 2. Transmission costs external to the ISO Control Area associated with an import schedule into the ISO could still apply even if the ISO curtails the import schedule; and 3. Load may justifiably want to be subsidized for consuming extra energy (i.e. a large commercial enterprise may ramp up production processes that would not be otherwise be economic absent an energy consumption subsidy). 35 The ISO stated in that filing, While the ISO believes these types of costs could justifiably result in a negative energy bid, the ISO does not believe it is reasonable to expect that such factors could result in a negative energy bid below -$30/MWh. FERC agreed with this argument, and modified the rule to make the floor a soft bid floor in the sense that if a generator could justify to FERC an economic bid price below -$30/MWh the ISO would be required to compensate them. In 2006, FERC directed the ISO to clarify that bids below - $30/MWh are subject to cost verification. The reasoning behind setting the energy bid floor at -$30/MWh, as articulated in these prior filings and FERC orders, did not consider the need for a liquid supply of DEC bids to The energy bid cap will increase to $1000/MWh on April 1, The bid floor is soft in the sense that a party can apply to FERC and receive authority to be able to submit bids below -$30/MWh. This section is written from the perspective of supply resources to simplify the discussion. It should be understood, however, that the energy bid floor is also relevant to demand resources, including both internal load and exporters that may be willing to increase their purchases of energy to relieve over-generation if the price were low enough. The ISO s Comprehensive Market Design Proposal dated May 1, 2002 can be found at: CAISO/M&ID Page 24 September 30, 2010

25 address the potential increase in the frequency and magnitude of over-generation due to renewable energy production. Nor did it consider the effects of renewable energy credits or production tax credits on a resource s opportunity cost. In addition, over the past several years, some market participants have argued that the current bid floor is too high and will harm market efficiency and liquidity by not allowing market participants, particularly potential exporters, to price their energy purchases to profitably move the energy to the most economical market in the HASP. 36 Some market participants have also argued that the asymmetry between the current bid floor and bid cap inadvertently favors one type of market transaction over another, and therefore they advocate symmetrical settings for the bid floor and bid cap. For all these reasons the ISO believes that it is timely to revisit those arguments and consider whether there is a need to lower the energy bid floor, and if so, to what level it should be lowered. There is already some indication that the current energy bid floor is too high to elicit economic DEC bids from variable energy resources. The combined effect of federal tax credits and the economic value of renewable energy credits (RECs) needed by California load-serving entities to meet their RPS requirements means that these resources would likely be unwilling to reduce their output for a payment of $30 per MWh, but may be willing to do so if they could earn a larger payment (i.e., by submitting a more negative energy bid). Tax credits for wind production along with other tax incentives guarantee these resources payments of close to $37/MWh. The renewable energy production tax credit (PTC) alone, currently at $21/MWh, is the primary federal incentive for wind energy and has been essential to the industry s growth. Alternatively, wind project developers can choose to receive a 30 percent investment tax credit (ITC) in place of the PTC for facilities placed in service in 2009 and 2010, and also for facilities placed in service before 2013 if construction begins before the end of Table 4 surveys the energy bid floors of the other ISOs and RTOs. Although ISO-NE currently does not have a negative energy bid floor, they are considering adopting one as a future enhancement to provide a more rational dispatch for intermittent renewable resources. PJM had a bid floor of $0/MWh but abandoned it in 2009, so now participants can bid negatively without limit. 37 Table 4 Comparison of ISO/RTO energy bid floors ISO/RTO Energy Bid Floor PJM No Bid Floor NYISO -$999.99/MWh MISO -$500/MWh CAISO -$30/MWh ISO-NE $0/MWh cite 37 PJM s Markets and Reliability Committee (MRC) approved changes to Manual 11 (Section 2) allowing negative bid offers at its June 17, 2009 meeting. 38 ISO-NE is considering moving to a negative energy bid floor in the near future. CAISO/M&ID Page 25 September 30, 2010

26 3.3.2 Stakeholder Comments Most stakeholders providing comments on this market rule supported lowering the bid floor. PG&E suggested that reducing the bid floor should be considered as a near-term market design change. CDWR argued that the current negative bid floor should be relaxed to increase market participation from generation and non-generation resources, including demand response, to address over-generation conditions. Shell Energy also observed that removing the bid floor could provide an incentive to develop additional storage capabilities. CalWEA specifically noted that this rule would encourage intermittent or variable energy resources (VERs) to participate in ISO markets. However, WPTF observed that lowering the bid floor below -$30/MWh can lead to undesirable side effects that adversely impact other market participants Options for changing the Energy Bid Floor One important implication that stakeholders must understand is that lowering the energy bid floor will allow the markets to produce lower locational marginal prices for settlement. The way that the ISO market systems operate, each market process (IFM, HASP, RTPD and RTD) consists of a scheduling run followed by a pricing run. The scheduling run establishes schedules and dispatch instructions in a manner that respects all the scheduling priorities and constraintrelaxation thresholds that are represented by market parameters in the software. 39 The prices that result from the scheduling run are not appropriate for settlement, however, because they are affected by market parameter values that are typically well outside the range of economic bids between the bid floor and the bid cap. Therefore each market performs a pricing run following the scheduling run, in which prices are determined by limiting these extreme parameters to the values of the energy bid floor and cap. As a result, except in unusual cases the LMPs are between the energy bid floor and the bid cap; i.e., between -$30/MWh and $750/MWh based on today s floor and cap levels. If the energy bid floor is lowered to a new value, say -$200/MWh for sake of discussion, then the range of LMPs produced by the markets will typically range between -$200/MWh and $750/MWh. Although the above may be obvious to most stakeholders, it is mentioned explicitly here as a necessary corollary of lowering the bid floor because the incentive effect of a lower bid floor depends critically on these lower energy bids being able to affect the market LMPs used for settlement. The ISO has identified the following questions for discussion regarding the bid floor, and invites stakeholders to offer their views on these questions and identify other questions that need to be discussed. 1. One impact of lowering the bid floor, based on the above discussion, is that when a significantly negative LMP occurs, all resources at that location (and probably nearby locations as well) will be settled at that LMP. A question for consideration in this initiative is whether lowering the bid floor could, through this effect, have adverse unintended consequences. For example, could there be adverse price impacts to resources with slower ramp rates, fuel issues and other constraints that would hinder their ability to decrement their output? 2. Another consideration is whether a lower bid floor could elicit sufficient downward dispatchability in the short term. In the case of system over-generation, a lower bid floor 39 The tariff provisions relevant to this discussion are found in sections 28.5, 31.4 and 34.2 CAISO/M&ID Page 26 September 30, 2010

27 should elicit additional export bids to reduce energy on the system. But in cases of local congestion, a lower bid floor will only elicit downward dispatchability to the extent there are sufficient resources in the right locations that are capable of responding to decremental instructions. 3. Are there potential market power concerns if the bid floor is lowered? 4. Non-generation resources are also important in this evaluation. Does the participation of demand and storage, for example, change dramatically if the bid floor is lowered? 5. Could marketers be more effective in responding to over-generation situations if the bid floor was lowered? To what extent would transactions to move energy out of California be more cost effective with a lower bid floor? 6. What is the appropriate level for a lower bid floor? Are there good reasons why the bid floor should be symmetrical with the bid cap? The ISO has identified the following options for discussion, and invites stakeholders to suggest other options that should be considered. Option 1: Retain the current bid floor level. The first option is to retain the current -$30/MWh bid floor and continue to monitor its effects on the ISO markets as renewable integration proceeds. The ISO expects, however, that this option will not be sustainable for the reasons discussed above, as it would not contribute to increasing the quantity of decremental energy bids in the RTM. Option 2: Revise the bid floor to be symmetric with the bid cap. Under this approach, the bid floor would be -$750/MWh until March 31, 2011, at which time it would become - $1000/MWh. In conjunction with this option we could also consider a phased approach, under which the bid floor would be reduced in a sequence of steps and would reach the ultimate - $1000/MWh level at some later date. Option 3: Revise the bid floor based on economic assessment. As discussed earlier, the initial bid floor value of -$30/MWh was established based on evaluation of the actual costs a resource could incur as a result of real-time reduction of its output below its IFM schedule. Moreover, that initial level was established as a soft bid floor, with an explicit allowance for resources to provide justification and seek approval to submit lower bids. One option for the present effort, then, would be to retain the concept of a cost-based soft bid floor. Under this option, we would need to identify the appropriate cost factors to consider in setting the new bid floor value. Also in conjunction with this option we should ask whether it would be appropriate to establish different bid floor levels for different resource types, based on the different cost impacts to which each type would be exposed. 3.4 Day-Ahead Scheduling of Renewables and Energy Market Performance Under the current market design, variable energy resources, like all physical resources, can schedule voluntarily in the day-ahead market. However, as noted above, there is no obligation to schedule, and if wind resources schedule day-ahead, any deviations from dayahead schedules would be settled financially at real-time prices. Consequently, the ISO has observed some limited day-ahead scheduling of wind resources, but little compared to expected CAISO/M&ID Page 27 September 30, 2010

28 Californiaa ISO next-day output. As the ISO sees additional variable generation at higher RPS levels, this lack of day-ahead scheduling may lead to a divergence of prices between the day-ahead and real , hour-ahead wind schedules diverged from day-ahead schedules by MWh, and time market. The following figure illustrates such divergence between day-ahead and real-time production at current wind production levels. On the day in late May 2010 presented, in hours real-timee production deviated from hour-ahead production by 400 MWh at times. These divergences did affect LMP convergence on the day in question RTD HASP IFM Wind Generation (MWh) Figure 6: Day-Ahead and Hour-Ahead Wind Schedules and Real-Time Production, Example Day in late May, 2010 The lack of day-ahead scheduling is not a reliability issue, as the ISO does include the day-ahead wind forecast in the RUC processs that follows the IFM. The RUC would commit additional units as needed to meet the wind forecast. Hence, the ISO utilizes the forecasted wind supply to minimize the potential for over-commitment of thermal generationn while ensuring 40 sufficient capacity is available to maintain grid reliability. The design issue before the ISO is whether to ensure the continued efficiency of the day-ahead and real-time markets through: 1. New day-ahead scheduling equirements on variable energy resources, perhaps with additional settlement incentives through PIRP; 40 We note that the issue of whether the day-ahead processess commit units with the right operational capabilities to provide load-following requirements also needs to be addressed. The sequential simulations conducted in the 20% RPS Study attempted to test for situations where the combination of day-aheadd and hour-ahead forecast errors and the hourly time-step commitment in those time-frames caused operational difficulties in real-time. Seee the 20% RPS Study, Section 5 for results. CAISO/M&ID Page 28 September 30, 2010