California ISO. Third Revised Straw Proposal. Renewable Integration: Market and Product Review Phase 1

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1 Third Revised Straw Proposal Phase 1 July 12, 2011

2 Draft Final Proposal - Phase 1 Table of Contents 1 Introduction and Overview Participating Intermittent Resource Program (PIRP) Background Proposal Effects of Convergence Bidding Intermittent dynamic transfers Energy Bid Floor Bid Cost Recovery Overview Proposed accounting of Energy Bid Costs and Start-Up Costs Proposed accounting of Minimum Load Costs Stakeholder comments on previous proposals Summary Next Steps...19 CAISO/M&ID Page 2 July 12, 2011

3 1 Introduction and Overview The ISO started Phase 1 of the Renewable Integration Market and Product Review, (RI-MPR) policy initiative in September, The purpose of this initiative was to identify short-term solutions for integrating renewable resources onto the grid. The scope of Phase 1 was comprised of two market design changes: (1) lower the energy bid floor to provide additional incentives for market participants, including variable energy resources (VER) to submit decremental (DEC) bids to enable the markets to manage over-generation and congestion more efficiently and transparently, (2) evaluate options for wind and solar resources so that they participate more fully in our markets, in particular the real time market. The current Participating Intermittent Resource Program (PIRP) provides disincentives for wind and solar resources to bid into the market. Specifically the program: Requires participating resources to self schedule rather than submit bids; Mutes the real-time price signals through monthly netting of deviations In addition, the current energy bid floor level does not allow wind and solar resources to recover the opportunity costs of reducing their energy output. These features create strong disincentives for many resources, and particularly VER, to submit decremental bids. The ISO s prior proposals in this initiative have generated robust and extensive stakeholder discussion. This third revised straw proposal reflects the further refinement of our previous proposals based on further analysis and consideration of stakeholder input and comment. The specific proposals included herein are: Update PIRP to limit new participation and change cost allocation. Resources with signed contracts before a certain date (to be determined) will be eligible to continue to participate in PIRP. Contracts signed after that date may not use the PIRP netting paradigm. Also the ISO will change PIRP s cost allocation so that PIRP uplift costs are allocated to scheduling coordinators with loads that contract with PIRP resources. Reduce the energy bid floor. The ISO will lower the bid floor from -$30/MWh to - $300/MWh. The objective of this rule change is to foster additional dispatch flexibility over time from both thermal and renewable resources. In particular, the bid floor is intended to account for the opportunity cost of curtailment faced by wind and solar resources and the scheduling coordinators that bid them into the market. Additional details regarding this element of the proposal are in Section 3 (no change from previous straw proposals) Change the bid cost recovery netting methodology. This policy change seeks to modify the ISO s netting methodology for bid cost recovery to ensure costs incurred by resources in one market do not diminish revenues received by resources in another market. The ISO recognizes that, without this change, it will erode the incentives to bid flexible resources economically into the real time market, which is counter to the overarching goal of this initiative. The proposals described in this paper will be discussed at a stakeholder meeting on July 19, RI-MPR actually began in July, 2010 with a discussion paper that set the stage for Phase 1 and Phase 2 of the project. RI-MPR Phase 1 identifies short term solutions while Phase 2 considers midand longer term solutions. The Phase 2 initiative was kicked off with a scoping paper and stakeholder meeting in April, CAISO/M&ID Page 3 July 12, 2011

4 2 Participating Intermittent Resource Program (PIRP) 2.1 Background PIRP was designed and implemented well before there was a clear expectation of the enormous growth of variable renewable resources that will occur as the result of increased RPS, without the foreknowledge of the technological advances that would improve forecasting for variable resources and enable such resources to better participate in real time markets, and without the benefit of the experience we have gained and knowledge we have learned from the studies of the operational impacts of renewable integration. As such, the PIRP rules were created and implemented without a concern for the ISO s ability to economically dispatch these resources through the real-time market. Prior to the start-up of the redesigned nodal market in April 2009, the PIRP rules were updated to be compatible with the new ISO market structure, both to remove some charge types and to reflect settlements at locational marginal prices. The revisions to PIRP for the new nodal market did not, however, reconsider the need for the ISO to be able to dispatch variable energy resources (VER), and as a result did not address those aspects of PIRP that impede the submission of economic bids. Under the current PIRP rules, participants of the program are treated differently than nonparticipants. Program participants are exempt from or receive special treatment for several of the market charges. Real-time deviations are netted over the month for market settlement. In exchange for these benefits, 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 real time market (75 minutes prior to the start of each operating hour) consistent with the ISO s resource-specific forecast of the resource s hourly output. Importantly, to obtain the PIRP financial settlement, PIRP resources are not allowed to submit economic bids into the ISO markets. If they do submit economic bids for any hour, then their energy settles at the interval LMPs during the hours in which the bids are submitted, without any netting of deviations. 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 bid and scheduled. Because participation in PIRP entails self-scheduling by VERs and precludes the submission of economic bids, continuation of PIRP would force the markets to rely more frequently on uneconomic curtailment rather than economic dispatch to resolve congestion and over-generation. Economic dispatch can accurately determine the most efficient amount by which to reduce the output of each resource to resolve over-generation conditions, whereas a manual approach (such as exceptional dispatch) will typically be less efficient. Under economic dispatch, the operator of a VER will receive dispatch instructions that reflect the most efficient amount by which to reduce output to manage the over-generation condition. Thus the resource operator can generally know that only the MW specified by the real time dispatch, including real-time forecasts of renewable production, are required to be curtailed and that the real time market will determine an efficient bid-based price for settling such curtailment. This is consistent with the over-arching goal for VER which is to minimize reliance on administrative measures to successfully participate in ISO markets and to provide incentives to supply economic bids. In this way, the market itself can relieve challenging system conditions while optimizing production by intermittent resources. CAISO/M&ID Page 4 July 12, 2011

5 2.2 Proposal The ISO proposes two changes to the current PIRP: Limit new participation in PIRP. The ISO plans to allow PIRP resources with contracts to continue in PIRP and freeze the program with the current participation rules. PIRP will not be available to new or amended VER contracts (after a date to be determined). Update cost allocation to more closely reflect cost causation. Currently, the ISO allocates uplifts resulting from the PIRP program to net negative uninstructed deviations. For some scheduling coordinators, the sole reason for remaining in PIRP is to get a share of the uplifts that that they must pay. The current proposal seeks to allocate the costs of PIRP to the load serving entities that contract with PIRP resources. The ISO will not make any change to the existing PIRP rules for participation. Scheduling coordinators of PIRP resources will continue to schedule in HASP in accordance with the hourly energy forecast provided by ISO. If resources comply with these rules they will not receive imbalance energy charges for deviations across each 10 minute settlement interval. Instead the energy deviations will be netted across a calendar month and settled at a weighted-average price. All resources participating in PIRP with a signed contract prior to the date the ISO files the RI- MPR Phase 1 tariff amendment at FERC may continue to participate in PIRP until the end of the initial term of their contracts. This includes resources with signed contracts that are not yet scheduling their resources into the ISO markets. If a contract has been signed prior to the date the ISO files this tariff amendment but the contracted resource is still under construction, it will be eligible to participate in PIRP during its initial contract term. However if there is no signed contract prior to the date the ISO files this tariff amendment, the resource will not be eligible to participate in PIRP. To be eligible for grandfathering the ISO will require certification of the date the contract was signed. Other required information will include the date of expiration of the initial term of the contract, the amount of MW, and the scheduling coordinator for the contracting load serving entity. A grandfathering request template will be developed for entities to submit this information. The scheduling coordinator information will be used to flag these loads for allocation of the uplifts. Currently, PIRP uplifts are allocated to net negative uninstructed deviations. For participating intermittent resource any real-time uninstructed imbalance energy (CC 6475) and real-time excess cost for instructed energy allocation (CC 6486) are accrued in the intermittent resources net deviation reversal settlement charge type (CC 722) each day. In a separate charge type, the intermittent resource net deviation settlement charge (CC 711), the participating intermittent resources deviations are accrued for the month. The amount in CC 722 is reduced by CC 711 at the end of the month. The resulting dollars are charged to net negative deviators in the intermittent net deviation allocation settlement type (CC 721). The ISO proposes to allocate the uplifts to load serving entities that contract with PIRP resources. Since all California load serving entities have the same 33 percent renewables portfolio standard target, all load serving entities that contract with PIRP resources should receive a proportional share of the applicable uplift. This approach means that scheduling coordinators that do not have load in their portfolio and scheduling coordinators for load without PIRP resources in their portfolio will not be allocated these costs. The following table is a CAISO/M&ID Page 5 July 12, 2011

6 simple example of how this proposal would distribute the allocation of uplift costs. Assume each LSE is a scheduling coordinator and each LSE is contracted with PIRP resources. Example Load serving entity/scheduling Coordinator LSE 1 LSE 2 LSE 3 LSE 4 LSE 5 Total PIRP Allocation Amount of metered load Amount of PIRP MWh Allocation of PIRP uplift costs $ $ In this example LSE 1 has 500 MWh of actual metered load in a month and 150 MW of energy produced by PIRP resources. The uplift costs are allocated according to the share of their monthly PIRP MWh. The monthly allocation determination is aligned with the monthly netting timeframe. Note that LSE 5 is an SC with no PIRP MWh associated with their load so they will not be allocated any of the uplift costs. For LSE 1 the calculation is the amount of PIRP MWh divided by the sum of the PIRP MWh of all LSEs with PIRP MW times the total allocation dollars 2.3 Effects of Convergence Bidding 150 MWh /550MWh* $1000 = $ The implementation of Convergence Bidding has increased the ability for VERs to participate in the day-ahead market and manage their risk due to high forecast errors. The highest risk for VERs is negative real-time deviations during periods of high prices. When VERs actual output is below their day-ahead schedule, the additional supply which must be procured in real-time can lead to higher prices than day-ahead. Since a VER has a negative marginal cost which exceeds the current bid floor, the need to minimize risk of exceeding their day-ahead schedule during low prices is a lesser risk. In addition, a newer VER has the capability to stop generating, whereas the VER cannot increase their fuel supply when the sun isn t shining or the wind isn t blowing. So when the bid floor is reduced beyond their negative marginal cost, the resource can manage this risk by submitting DEC bids in the real-time market. Example: Assume a VER has a 100MW day-ahead forecast with an error of +/- 25%. In order to hedge their exposure to real-time prices if the resource has negative deviations, the resource submits a virtual demand bid equal to the negative forecast error or 25MW at the same generation location. The 25MW virtual demand bid is liquidated at the real-time LMP and protects the resource from exposure to the real-time price for their forecast error. If the resource generates above 75MW the resource benefits from the higher real-time price. CAISO/M&ID Page 6 July 12, 2011

7 2.4 Intermittent dynamic transfers The recent Dynamic Transfer stakeholder process looked to this market design effort to provide guidance for Intermittent Dynamic Transfers. Given the fact that the PIRP will not be changed or updated this time, the ISO does not believe that is appropriate to include these types of resources into PIRP. In addition, the ISO is creating measures for intermittent dynamic transfers to update their forecast intra-hour to help deal with the variability. Internal wind and solar resources are more dependent on the PIRP because VER that reside outside of the ISO Balancing Authority have options to mitigate their variability within their own BA that are not available to internal resources. Additionally, allowing external VER to utilize PIRP potentially creates an incentive for these resources to send their variability and balancing responsibility to the ISO and then buy a firm schedule back out of the ISO at the HASP price. The ISO prohibits internal resources from exporting so this is not a problem internally. 3 Energy Bid Floor The ISO spot markets currently require that the economic bids submitted by scheduling coordinators to buy and sell energy have prices no greater than the cap of $1000 per MWh and no less than the floor of -$30 per MWh. Negative bids serve an important function in the spot markets; among other things they are used by supply resources to elicit payments to decrement their energy production from previously scheduled levels, and by demand (including exporters) to increase their energy purchases from the market at times when there is excess supply. There is currently a limited supply of decremental energy bids to enable the ISO market systems to economically reduce energy supply to balance demand when needed, especially in off-peak hours that will become increasingly susceptible to much higher levels of over-generation as additional renewable production comes on-line. The key objective of this proposal is to provide price signals to incent resources to submit decremental bids. Although some resources are constrained based on contractual and environmental factors and do not have the flexibility to adjust their output during over-generation situations, there are other resources that simply cannot reduce output economically given the current energy bid floor. In particular, the current bid floor level of -$30/MWh is not sufficient to compensate reductions in energy output from VERs who receive additional revenues outside of the ISO markets for their energy production. The current bid floor level at -$30/MWh does not allow SCs to bid economically in many cases. Market design changes to increase the provision of decremental bids are an important element of the present initiative, to improve the ISO s capability to use market-based optimization to manage over-generation conditions, real-time congestion and possibly system ramps in the future. If there is not a sufficient supply of decremental bids in any of these conditions, the ISO must issue non-economic instructions (i.e., instructions that are not based on energy bids) for resources to reduce energy supply to balance the system. 2 For a number of reasons these noneconomic dispatch instructions result in less efficient curtailment of resources. Such instructions 2 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. CAISO/M&ID Page 7 July 12, 2011

8 are determined by the market optimization through the use of market parameters that are outside the allowable range of economic bids and hence may result in decremental dispatch of plants with higher willingness to pay to remain in operation. 3 Over the past year, the ISO has faced numerous instances where there were insufficient decremental bids in the market, thereby indicating that a reduction in the bid floor is needed even in the near term. Most recently instances of overgeneration with lack of decremental bids to help manage congestion on the grid more effectively and economically have increased in frequency and are expected to increase over time with the addition of VERs in the next 2-3 years, particularly in high hydro conditions, thereby making such changes an even higher priority. 4 The original reasoning which supported setting the energy bid floor at -$30/MWh, as articulated in prior filings and FERC orders, did not take into account the effects of renewable energy credits or production tax credits on a resource s opportunity cost and, hence, a unit s likely unwillingness to reduce its output for a payment of only $30/MWh. For more background regarding the history for setting the bid floor at -$30/MWh, refer to the Issue Paper which provides a detailed breakdown. 5 Accordingly, the ISO proposes to lower the energy bid floor to -$300/MWh. Wind and solar resources are not likely to reduce their output unless the floor is at least at this level. There a number of data points that the ISO used in determining the appropriate amount that the energy bid floor needed to accommodate: Renewable energy credits (RECs) are capped at $50/MWh. 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, 6 is the primary federal incentive for wind energy and has been essential to the industry s growth. The FERC Electric Quarterly Reports (EQR) filed by sellers in the ISO area for the 4 th quarter of last year reported prices greater than $150/MWh for energy sales during that period. 7 Additionally, the CPUC confirmed that a recent RFO issued for solar photovoltaic facilities had a cap of $295/MWh. Contract penalties associated with curtailing energy production places additional pressure on VERs to produce rather than decrement their energy. 3 For example, New York ISO has noted in comment on the FERC Notice of Inquiry Seeking Comment on the Integration of Variable Energy Resources that negative LMPs in the absence of sufficient decremental bids has caused wind plants to curtail at higher quantities than would have been necessary if the decremental dispatch was conducted through the economic dispatch function of the ISO. ( _NOI_ pdf) 4 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 season and hour of day from April 1, 2009 to June 30, Issues Paper Renewable Integration Market and Product Review Phase 1, September 30, The renewable energy production tax credit is an income tax credit of 2.1 cents/kilowatt-hour and is allowed for the production of electricity from utility-scale wind turbines. This incentive was created under the Energy Policy Act of Through the American Recovery and Reinvestment Act (ARRA), Congress acted to provide a three-year extension of the PTC through December 31, The FERC EQR reports are located at: CAISO/M&ID Page 8 July 12, 2011

9 The appropriate floor must be low enough to incent resources with these types of payments to curtail their production. A number of stakeholders supported the strategy of lowering the bid floor to -$1,000/MWh (in stages) as outlined in the straw proposal; however there were others who suggested that this approach was too extreme and that the floor should only be lowered to a level that offsets the incentives provided to resources to generate. DMM also recommended lowering the bid floor but not to the extent proposed. DMM indicated that it was not clear that lowering the bid floor to -$1,000 would provide more incentive for resources to bid decrementally than a higher bid floor. The ISO changed its focus on the energy bid floor level so that we could provide incentives for resources, like VERs, that seem to be able to respond given the right circumstances. 4 Bid Cost Recovery 4.1 Overview The ISO proposes a near-term change to bid cost recovery (BCR), to separate out the netting of BCR so that day ahead (DA) is separate from real time (RT) and Residual Unit Commitment (RUC). 8 This proposal also addresses the complication of Multi-Stage Generating Unit (MSG) costs and revenues for which the separation of minimum load cost into day-ahead and real-time becomes necessary when BCR is netted within individual markets rather than across them (i.e. separate netting between DA and RUC/RT). The rationale for adopting this change as part of the RI-MPR Phase 1 Straw Proposal is that lowering the energy bid floor in order to provide incentives for VERs to economically bid into the ISO market can expose generators to large negative prices in RT when they are rampconstrained. Offsetting day-ahead costs with real-time revenues can substantially lower a resource s potential BCR. This can provide generating resources to self-schedule in the RT in order to protect their BCR from the DA. This is directly opposed the intent of the proposal to lower the Energy Bid Floor. By diluting the incentive for decremental bids in the real-time, without this change the RIMPR Phase 1 proposal would have the perverse resulting of worsening the ISO s ability to manage the grid given the increasing number of VERs on the system. The ISO proposes to retain the day-ahead bid cost recovery rules that require the accounting of day-ahead costs on an hourly basis and that require netting of DA revenues interval-by-interval (i.e., by trading hour) against DA costs. The ISO also proposes to retain the daily netting of costs and revenues across the 24 hours of the day-ahead market. The ISO proposes to no longer apply the Metered Energy Adjustment Factor (MEAF) in the DA BCR calculations. This is consistent with the ISO s proposal to eliminate the netting of costs and revenues in DA against those in RUC and RT. Removing the netting severs the connection between the two time-periods for the purpose of BCR calculations. Thus the ISO asserts that the DA financial market should be made whole on its own rather than depending on RT performance. In its 2006 order enabling the ISO s new nodal market design, the Federal Energy Regulatory Commission stated the following: We agree with SoCal Edison and WPTF/IEP that the current bid cost recovery penalties for deviation outside of the tolerance band are improper. However, we do not agree fully with the CAISO s proposed solution. We do not believe the CAISO s response 8 Note that the CAISO is currently conducting a review of equivalent practices at other ISOs, and this benchmarking will be included in the subsequent iteration of this Straw Proposal. CAISO/M&ID Page 9 July 12, 2011

10 adequately addresses concerns regarding the appropriate determination of bid cost recovery payments. Resources that fall short of day-ahead dispatch instructions should only be guaranteed the recovery of costs associated with the energy actually provided, and should not receive payments for deviations from dispatch instructions. When a resource s energy bid exceeds the LMP, it is not appropriate to provide an uplift payment to cover the revenue gap for energy that is not actually produced when instructed. However, a resource that starts up and provides more energy than is instructed by the CAISO should retain the original recovery calculated by the CAISO in the day-ahead market, since the spot market would be receiving the full amount of energy (and more) that it agreed to pay for in the day-ahead market. However, the resource should not be eligible for any additional bid cost recovery associated with its additional, uninstructed output. Thus, the resource is paid only for scheduled energy, and is not paid for any energy in excess of its schedule. Units that are committed in the day-ahead market, and do not start-up, should not receive any bid cost recovery payments. We direct the CAISO to revise the MRTU Tariff accordingly in a compliance filing to be submitted within 60 days of the date of this order. [emphasis added] Accordingly, the ISO provided bid cost recovery for only those portions of the day-ahead market that were actually delivered. However, in light of the need to ensure there are sufficient incentives to provide decremental bids in the real-time, the ISO now proposes to modify this requirement. To achieve the targeted incentives, the ISO proposes to split the netting between the DA and RUC/RT markets. The logic of separating the BCR netting for is inconsistent with the logic of pro-rating DA costs (i.e., applying MEAF) based on performance in the RT. The ISO proposes to net out RT and RUC market revenues against RT and RUC market bid costs. If, when the revenues and costs are netted, there is a shortfall across the 24-hour day then the resource will receive BCR. RT MEAF will still be applied so that the RT performance of the resource is considered in calculating RT BCR. The rationale for the proposal to eliminate the DA MEAF is that, in the overall CAISO design, the day-ahead is a financial market whereas actual operation occurs in real-time. If a resource does not deliver the incremental or decremental energy in real-time, it will not be subject to bid cost related to that undelivered energy. The current definitions of Self-Commitment Periods will continue to apply. No changes to the Expected Energy Calculations are needed. What we are addressing here is when the unit is both ISO committed in both DA and RT. 4.2 Proposed accounting of Energy Bid Costs and Start-Up Costs Under this proposal, the inclusion of energy bid costs and start-up costs (SUC), will largely follow current practices. Specifically, a resource s DA energy bid costs and energy revenue are included in the DA BCR calculation. RUC capacity bid costs, RT energy bid costs and RUC capacity payment and RT energy revenues go into the RT BCR calculation. The ISO proposes that the current start-up cost rules apply except the new distribution rule after the application of the current rules. The new distribution rule is as follows: in the case of overlapping commitment periods, the ISO proposes that for any start-up corresponding to a continuous ISO commitment period, for both DA and RUC/RT (i.e., the DA and RUC/RT commitment periods overlap), the start-up cost be distributed to the relevant settlement intervals between the DA and RT BCR calculations based proportionally on the DA and RT Minimum Load Energy (MLE) respectively within the commitment period. CAISO/M&ID Page 10 July 12, 2011

11 After this distribution, the meter values will be used to qualify SUC in each individual market using the same rules as today. 4.3 Proposed accounting of Minimum Load Costs For non-msg resources, the ISO proposes that minimum load costs (MLC) be calculated the same as it is today. In addition to that, the market of the MLC will always be aligned with the market of the MLE. Elimination of the netting across DA and RUC/RT necessitates the changes to MSG MLC allocation described in this proposal. In the case of MSG resources, the assignment of minimum load costs and MLE revenues to either DA or RUC/RT is complicated by the fact that a change in configuration between those two settlement periods can result in the same generating resource having ML Costs and Energy for the same operating interval in both DA and RT because different configurations with their own ML costs could be scheduled in DA and RUC/RT. This design for assigning MLC and MLE to either the DA or the RUC/RT Bid Cost Recovery calculation captures costs and revenues for an MSG resource s actual movement between configurations between the DA and RUC/RT. The portion of the RUC/RT ML Energy and costs that are incurred by the MSG resource moving from the DA configuration to the RT configuration is attributed to the RT. That is to say, only the proportion of a configuration s MLC that is incurred by moving from the DA configuration to the RT configuration is attributed to RT for the purpose of the BCR calculation. Note that there is no proposed change to the Transition Cost allocation or payment. Four cases are described below to provide examples of how the proposed proportioning would work for over-lapping and for non-overlapping MSG configurations, in both the incremental and decremental directions. 9 The following four new rules apply when MSG resource is both committed by ISO in Day-ahead and Real-time markets but in different configurations. When there is self commitment in either market, existing rules apply to self commitment period. When the MSG resource is committed in the same configurations between day-ahead and real-time, existing rules apply. A few notes on notation: 1. Configuration 1 is denoted as C1. 2. Other measures MLC, Pmin, Pmax when specific to a configuration are written as, for example, Pmin-C1. 3. A configuration with a higher Pmin has a higher number. For example, C2 is a higher configuration than C1. Incremental Cases: In the DA, the MSG resource is in C1 and RT it is in C2 o CASE 1 incremental change, non-overlapping configurations: RT MLC = MLC-C2 * (Pmin-C2 Pmax-C1) / Pmin-C2. See this range indicated by the bracket below. DA MLC = MLC-C1. See this range indicated by the bracket below. 9 Prior to the July 19, 2011 stakeholder meeting to discuss this Straw Proposal, the ISO will post detailed examples of how these rules would apply. CAISO/M&ID Page 11 July 12, 2011

12 In the range between Pmin-C2 and Pmax-C1, ML costs are used to represent an inferred energy bid cost. MWh Pmax-C2 RT MLC RT Schedule Optimal Energy RT Minimum Load Energy DA Schedule DA Bid-Awarded Energy DA Minimum Load Energy Pmin-C2 Pmax-C1 Pmin-C1 o CASE 2 incremental change, overlapping configurations: RT MLC = MLC-C2 * (Max(0, Pmin-C2 Day-Ahead Schedule)) / Pmin-C2. See this range indicated by the bracket below. DA MLC = MLC-C1. See this range indicated by the bracket below. This rule applies to all cases in which C1 and C2 overlap, as well as the case in which the Pmax of the lower configuration is equal to the Pmin of the higher configuration The RT MLC captured in this way represents the inferred energy bid cost of the movement from the DA scheduled MW to the Pmin of the RT configuration. Note that, because the configurations in this case are overlapping, a resource can have a DA schedule in C1 that is at a MW level higher that the Pmin of C2 to which it is dispatched in RT. Thus, a resource may have to move down in order to transition to a higher configuration. In this case there is no additional bid cost inferred from the MLC. CAISO/M&ID Page 12 July 12, 2011

13 MWh Pmax-C2 RT Schedule Optimal Energy Pmax-C1 RT MLC RT Minimum Load Energy DA Schedule DA Bid-Awarded Energy Pmin-C2 Pmin-C1 DA Minimum Load Energy Decremental Cases: DA in C2 and RT in C1; C2 is higher than C1 Note: Although the formulae are different, the decremental cases are simply the logical reversals of the incremental cases. o CASE 3 decremental change, non-overlapping configurations: RT MLC = (-1) * MLC-C2 * (Pmin-C2 Pmax-C1) / Pmin-C2 DA MLC = MLC-C2 In the range between Pmin-C2 and Pmax-C1 the MLC are used to represent the resource s energy bid cost. o CASE 4 decremental change, overlapping configurations: RT MLC = (-1) * MLC-C2 * (Max(0, Day-Ahead Schedule Pmax-C1)) / Pmin-C2 DA MLC = MLC-C2 This rule applies to all cases in which C1 and C2 overlap, as well as the case in which the Pmax of the lower configuration is equal to the Pmin of the higher configuration The RT MLC captured in this way represents the inferred bid cost of the movement from the DA scheduled MW to the Pmax of the RT configuration. CAISO/M&ID Page 13 July 12, 2011

14 5 Stakeholder comments on previous proposals The ISO received 15 sets of stakeholder comments on our previous straw proposal. Those comments were valuable to ISO staff in further evaluating what had been proposed and as such the ISO significantly changed the RI-MPR Phase 1 proposal. Many of the comments that related directly to the specifics of the PIRP proposal and are not reflected in the following summary, since it has changed significantly. For a complete review of all the stakeholders comments, please visit the following webpage - Stakeholder Comments Response Brookfield Calpine ISO should extend grandfathering to PPAs that were executed prior to PIRP elimination. Cannot support lowering the bid floor without making bid cost recovery changes concurrently. This current proposal allows grandfathering for contracts that are signed prior to the FERC filing date. The current proposal includes changes to bid cost recovery. CalWEA The preliminary 33% analysis shows that there is a need for up to 1200 MW of additional downward flexibility CalWEA understands that this would only happen over a few hours each year. The ISO has not demonstrated that PIRP elimination would result in additional economic bids from VER. Why is the ISO proposing to eliminate PIRP based on cost impacts, but not other costly programs, such as BCR for ramping energy and HASP pricing for imports? Proposal does not address potential costs and risks from changes in the day ahead must offer obligation CalWEA does not agree that 3 years is enough time for contract rewrites. ISO must consider mitigation That is a possible scenario. In the current proposal PIRP will not be eliminated for existing contracts. By changing PIRP cost allocation, lowering the bid floor and changing the bid cost recovery rules the ISO expects that more VERs will be in the market and submitting economic bids. The ISO is not currently proposing to eliminate PIRP. The ISO does not plan to change any RA obligations as a result of this proposal. Understood. The ISO has changed its position with CAISO/M&ID Page 14 July 12, 2011

15 Iberdrola IEP measures together with PIRP elimination proposal. Recommends waiting to consider this change until Phase 2. Wind generation output was sold under long term PPAs that rely on the continuation of the PIRP program. Recommends grandfathering for existing wind generation facilities that are operating under these contracts. The current scheduling timeframe makes it difficult to accurately forecast significant wind generation ramps. The primary focus of the ISO should be on market structure changes that will reduce the overall cost to effectively and reliably integrate these resources. Iberdrola analysis shows that scheduling 30 minutes prior to the operating hour (rather than 75) provided an average reduction in imbalance energy of more than 30%. When a VER acts as its own scheduling coordinator, there is no way to recover costs associated with the elimination of the PIRP program Allow VERs operating under PIRP to modify schedules closer to real-time so as to minimize schedule deviations. Create incentives for VER resources to participate in realtime markets via the submission of dec bids (simultaneous with PIRP). Resource schedules should be automatically removed from PIRP settlement in any interval that VERs submit dec bids and the dec bid is accepted. regard to PIRP elimination. We will continue PIRP for resources with existing contracts. This is within the scope of the current proposal. The ISO agrees and that is included as an element of the RI-MPR Phase 2 effort. This discussion is appropriate for RI-MPR2 Phase 2 effort. The ISO proposes to allocate costs to the LSE using PIRP resources. Agreed. This is within the scope of RI-MPR Phase 2. This proposal was considered however, the ISO does not wish to enhance the current PIRP program. The ultimate goal is for the market to be technology agnostic and is one of the principles of the RI-MPR Phase 2 effort. CAISO/M&ID Page 15 July 12, 2011

16 MegaWatt Storage Farms NRG Energy, Inc. Perhaps should require PIRP participants to submit dec bids. Grandfather existing contracts that have no reasonable means of cost recovery or alternatively have a technology not suitable for responding to real-time price signals. Recommend a symmetric price cap and floor. Opposes lowering the bid floor prior to reforming bid cost recovery. The focus of this proposal is to allocate costs to LSEs that use PIRP resources The ISO proposes lowering the energy bid floor to -$300/MWh at this time. We may consider other options after we have gained experience at this level. Changes to bid cost recovery are included in this proposal. PG&E Reduce the bid floor to - $200/MWh rather than - $300/MWh. Over-generation is usually in off-peak hours and is associated more with wind rather than solar. Powerex Implement bid floor reduction coincident with implementation of bid cost recovery changes. Recommends grandfathering resources with a PGA at the time of the effective date for the life of their contract/ qualify to stay in PIRP through the term of the initial contract. Extend PIRP to pseudo tie resources. To do otherwise would be discriminatory treatment. Work with PUC and IOUs to address the barrier to economic curtailment created by RPS compliance. Bid floor should be symmetric to the bid cap at -$1000/MWh. Asymmetrical bid cap and floor will lead to unintended and undesirable market outcomes. The ISO proposes lowering the energy bid floor to -$300/MWh at this time. We may consider other options after we have gained experience at this level. Changes to bid cost recovery are included in this proposal. Agreed. Given the fact that the PIRP will not be changed or updated this time, the ISO does not believe that is appropriate to include these types of resources into PIRP. Agreed. The PUC and ISO should work in coordination with regarding to meeting RPS goals. The ISO proposes lowering the energy bid floor to -$300/MWh at this time. We may consider other options after we have gained experience at this level. CAISO/M&ID Page 16 July 12, 2011

17 Sempra Generation Six Cities SMUD Supports ISO intention to start a bid cost recovery stakeholder process in the very near future. Elimination of PIRP would impact the economics of resources that act as their own scheduling coordinators and cannot pass incremental charges through their LSEs. They should be grandfathered. Software should accommodate simultaneous self-schedules and bids from PIRP resources. Self schedules could be automatically removed from PIRP settlement anytime a dec bid is struck. Recommend establishing a mechanism to allocate PIRP costs to LSEs based on their respective renewable portfolios. Dynamic transfers are no different than internal resources in their use of the PIRP program. The bid floor should be lowered to a more moderate level such as -$40/MWh or -$50/MWh which is based on realistic expectations. The ISO should not allow new resources to use PIRP, limit it to resources currently enrolled. The ISO needs to commit to an ongoing process to develop a program to replace PIRP. Recommends that once the bid floor is lowered, PIRP would only apply in intervals when the LMP is positive, If the LMP is negative, the resource receives the negative LMP for any generation. Resources that are eligible for grandfathering should get the Changes to bid cost recovery are included in this proposal. Agreed. This is captured in the current proposal. The ISO considered this idea but the timing of implementing these types of changes brings us close to the RI-MPR Phase 2, so these would be very temporary changes. The current proposal uses this principle. Given the fact that the PIRP will not be changed or updated this time, the ISO does not believe that is appropriate to include these types of resources into PIRP. The ISO proposes lowering the energy bid floor to -$300/MWh at this time. We may consider other options after we have gained experience at this level. The current proposal incorporates this ides. We have started RI-MPR Phase 2. The ISO considered this idea but the timing of implementing these types of changes brings us close to the RI-MPR Phase 2, so these would be very temporary changes. The ISO does not propose to change the rules for PIRP payments. CAISO/M&ID Page 17 July 12, 2011

18 SCE SWP monthly average price for their entire output because they are unable to mitigate the effect of negative LMPs by curtailing output. The ISO seems to be authorizing scheduling/bidding of an amount of energy in either the IFM or RT market that is different than what the entity reasonable expects to generate to mitigate risk. This is contrary to the tariff. If the ISO grandfathers existing projects due to financial considerations, the associated PIRP uplift charges should be allocated to the contract counterparty rather than spread market-wide. Cautions against lowering the bid floor without proper changes to bid cost recovery. The ISO suggests that products such as convergence bidding can be used to mitigate risk for VERs. This feature is included within the tariff. The current proposal incorporates this concept. The ISO proposes to lower the energy bid floor in conjunction with bid cost recovery changes. WPTF ISO Department of Market Monitoring Re-couple the energy bid floor proposal with the bid cost recovery changes. Supports lowering the bid floor to -$150/MW. Evidence suggests this is sufficient to incent the majority of wind producers to reduce output. Convergence bidding is an efficient method for variable energy resources to mitigate forecast and price risk in the real time market Market efficiency and the ability to manage the grid reliably should take precedence over the potential burden of renegotiating contracts for what is estimated to be a $1.55/MWh change in benefits, especially given risk management opportunities The ISO proposes to lower the energy bid floor in conjunction with bid cost recovery changes. The ISO proposes lowering the energy bid floor to -$300/MWh at this time. We may consider other options after we have gained experience at this level. Agreed. Agreed. CAISO/M&ID Page 18 July 12, 2011

19 6 Summary Phase 1 of the Renewable Integration Market and Product Review consists of three elements. Update PIRP to limit new participation and change cost allocation.. Reduce the energy bid floor from soft bid floor of -$30/MWh to a hard bid floor of - $300/MWh. Change the bid cost recovery netting methodology. 7 Next Steps In July 2010, the ISO published a discussion paper which began the RI-MPR Phase 1 stakeholder process. This was followed by a succession of papers and presentations including an issue paper, a straw proposal, a revised straw proposal and a presentation regarding potential changes to PIRP 10. Each step of the way stakeholders provided both verbal and written comments 11. These informative and helpful comments that have been proposed during ISO s market design effort help to craft the current second third revised straw proposal. Components and Schedule Objectives of Phase 1 Proposal Item Date Publish Phase 1 Third Revised Straw Proposal July 12, 2011 Stakeholder Meeting July 19, 2011 Stakeholder Comments July 27, 2011 Publish Phase 1 Draft Final Proposal August 17, 2011 Stakeholder Conference Call August 24, 2011 Stakeholder Comments August 31, 2011 Board of Governors Meeting Phase 1 August 24, Additionally there was a straw proposal, draft final proposal and revised draft final proposal devoted to Regulation Energy Management. All documents are available at the following link: All stakeholder comments are available at the following link: CAISO/M&ID Page 19 July 12, 2011

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