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  • Completed stakeholder initiatives
    • Administrative pricing rules
      This initiative will examine tariff provisions regarding market intervention in the event of significant system emergencies and the settlement implications of force majeure events. The ISO committed to this process in its FERC approved petition to waive tariff provisions for setting administrative prices and settling real-time market transactions related to the September 8, 2011 Pacific Southwest power outage.
    • Affected system impacts of generator interconnection
      Interconnecting generation facilities can cause reliability concerns on directly connected and adjacent electric systems. The ISO tariff addresses these situations at a high level. Through this initiative, the ISO proposes processes and principles that should be included in the Business Practice Manual for Generator Interconnection Procedures to address these impacts. These changes will then be vetted through the BPM change management process.
    • Bid cost recovery and variable energy resource settlements
      The initiative explores ISO tariff solutions for settling residual imbalance energy for economically bidding variable energy resources and the persistent deviation metric broadly applied to variable energy resources. Additionally, the initiative presents refinements to the day-ahead metered energy adjustment factor. Please see the associated market issues bulletin describing residual imbalance energy settlement and ramp rate changes.
    • Bid cost recovery enhancements
      This initiative explores potential market design changes to the real-time and day-ahead bid cost uplift allocations and bid cost recovery for units operating across multiple days. (Formerly Two-tier allocation of real-time bid cost recovery)
    • Capacity markets
      Over the last few years, California has designed and implemented a new resource adequacy program. A key next step in the resource adequacy evolution is to determine whether a capacity market would be a beneficial complement to the phased-in resource adequacy plan, and if so, what are the appropriate attributes of a capacity market.
    • Capacity procurement mechanism
      The California ISO is conducting a stakeholder process to design the Interim Capacity Procurement Mechanism and Exceptional Dispatch replacement tariffs before the current ones expire on March 31, 2011. The ISO will present a proposal to its Board of Governors during the November 2010 Board meeting to comply with a FERC filing deadline of 120 days before the sunset date. The proposal to the Board will likely contain these elements: successor to the ICPM tariff, update of exceptional dispatch pricing, and extension of bid mitigation for Exceptional Dispatch.
    • Data release and accessibility
      With the start up of the California ISO's new market system based on Locational Marginal Pricing (LMP) on April 1, 2009, stakeholders have expressed a desire for the release of additional information that would enable them to better understand market results and participate more effectively in the ISO markets.
      In response, the ISO committed to conducting a stakeholder process to explore the issue of data release and accessibility in ISO markets and to implement appropriate enhancements to its current data provision practices: Phase 1 - Transmission Constraints; Phase 2 - Convergence Bidding Information Release; Phase 3 - Other types of market data to support well-functioning, competitive ISO spot markets, including Price Discovery and Outage Information.
    • Data release and accessibility phase 1 - transmission constraints
      With the April 1, 2009 implementation of the California ISO new market system based on Locational Marginal Pricing, stakeholders expressed a desire for the release of additional information enabling them to better understand market results and more effectively participate in the ISO markets. In response, the ISO is conducting a stakeholder process to explore the issue of data release and accessibility in ISO markets and to implement appropriate enhancements to its current data provision practices.
    • Energy Imbalance Market foundation
      The California ISO worked extensively with stakeholders to provide Energy Imbalance Market (EIM) services to other balancing authorities in the west.
    • Energy Imbalance Market governance development
      The implementation of EIM necessitates that all entities, whether inside or outside California, are given a voice in the decision-making process going forward. The EIM Transitional Committee is a stakeholder body tasked with developing a long-term governance structure and advising the Board on EIM. Through this initiative the EIM Transitional Committee will first evaluate the general relationship between the ISO and EIM Governing Body, and criteria for evaluating governance proposals. Then the committee will vet its proposal for long-term EIM governance with stakeholders.
    • FERC Order 1000 compliance - phase 1
      The ISO is modifying its tariff to incorporate the regional requirements specified by FERC Order No. 1000. Through Phase 1 of this initiative the ISO developed with stakeholders the necessary tariff amendments to comply with the regional requirements of FERC Order No. 1000 for planning and cost allocation, and non-incumbent transmission developers. The ISO must make its compliance filing with FERC by October 11, 2012.
    • FERC Order 1000 compliance - phase 2
      The ISO is modifying its tariff to incorporate the interregional requirements specified by FERC Order No. 1000. Through phase 2 of this initiative, the ISO is working with its stakeholders and the neighboring regional planning entities to develop common provisions to comply with the interregional requirements of FERC Order No. 1000 for transmission coordination and cost allocation. These provisions must be incorporated into each region’s open access transmission tariff. The ISO must make its compliance filing with FERC by April 11, 2013.
    • Generated bids and outage reporting for non-resource specific RA resources
      Suppliers of Resource Adequacy (RA) capacity have the obligation to bid that capacity into the California ISO market. The ISO therefore has Tariff authority to insert generated bids for RA resources that fail to bid into the market. There are gaps in this process, however, when it comes to the case of system (or import) resources that are not resource-specific but do have RA contracts (NRS-RA resources). Through this stakeholder effort, the ISO will work with market participants to address two issues required for implementing insertion of generated bids for NRS-RA resources that fail to offer into the ISO markets. The first issue is the question of what bid price to insert for automatically generated bids, and the second is that of outage reporting for these resources.
    • Generation interconnection cluster 4 phase 1 methodology
      The ISO is considering an alternative methodology to the phase 1 network upgrade analysis used to assess the cost ceiling and posting requirements for interconnection cluster 4 generation. The alternative methodology under consideration will not impose a limit on the amount of generation that actually proceeds through phase 2. The current methodology, if applied, would lead to unrealistic results because of the significant volume of interconnection requests received in the cluster 4 window, which closed on March 31, 2011. No change in methodology is expected for the phase 2 analysis and all generation that advances from cluster 3 and 4 phase 1 will be studied together in the cluster 3 and 4 phase 2 process.
    • Imbalance conformance enhancements
      This initiative will clarify the ISO’s authority to conform for imbalance in both real time and the day ahead markets. The purpose of conforming is to maintain reliability of the bulk electric grid. It will also propose enhancements for the conformance limiter. The purpose of the limiter is to ensure price spikes do not result from artificial market infeasibilities.
    • Integrated balancing authority areas
      The California ISO is holding stakeholder discussions on the ISO's efforts to model the systems of Integrated Balancing Authority Areas (IBAA) under the ISO's Market Redesign and Technology Upgrade (MRTU) program. The ISO MRTU program encompasses a comprehensive overhaul of the ISO electricity markets designed to both enhance reliability and increase the efficient utilization of the transmission system. As part of its larger effort to improve its ability to reliably manage congestion on the transmission system, the ISO has identified needed improvements to how it models and prices transactions to and from IBAA. IBAA are those Balancing Authority Areas or systems that are not part of the ISO Balancing Authority Area but are closely interconnected/integrated with the ISO's system.
    • Late payment enforcement action
      The California ISO previously held a Credit Policy Stakeholder process during fall 2008 and a progressive discipline process for late payers was developed with stakeholders and approved by the ISO Board of Governors in December 2008. Much of the process was implemented March 31, 2009, but one key element, financial penalties, was deferred until after implementation of the ISO's new market. This tariff amendment will implement financial penalties and the ISO's right to suspend or terminate a repeat offender's right to participate in the ISO markets.
    • Load granularity refinements
      Through this initiative the ISO and stakeholders evaluated alternatives for the level of granularity load should bid, schedule and financially settle in the ISO market. — FERC approval: Oct. 21, 2015 (ER02-1656-038) (ER06-615-061)
    • Merced Irrigation District transition
      The California ISO and Merced Irrigation District have executed a memorandum of understanding that will form the basis of a transition agreement, once negotiations are authorized by the ISO Board of Governors. The community-owned electric utility is considering becoming an ISO participating generator owner, utility distribution company load serving entity and participating transmission owner. If the ISO and Merced were to complete the transition agreement this year, Merced could become a participating generator by summer 2014 and a participating ISO transmission owner as early as July 1, 2015.
    • Metering rules enhancements
      The ISO metering requirements have remained relatively unchanged since 1998. Meanwhile the energy landscape has dramatically changed with the growth in renewables, energy storage, distributed energy resources, energy imbalance market expansion, complex metering configuration needs, and efforts to integrate western balancing areas with the ISO. This initiative will review existing metering requirements and propose possible revisions to accommodate these changes.
    • Natural gas pipeline coordination tariff modifications
      The ISO is proposing draft tariff language to clarify the policies on sharing information about forced and unforced generation and transmission outages with utilities operating natural gas pipelines in order to ensure that pipeline outages will not undermine reliable operation of the grid.
    • Natural gas pipeline penalty recovery
      This initiative will consider extending the 2012 Board-approved commitment cost policy to include emergency conditions when ISO and pipeline owner operators are coordinating for reliability reasons. The current policy allows generators to seek recovery of natural gas pipeline penalties, such as those associated with PG&E’s operational flow orders, only in limited, non-emergency circumstances through the ISO bid cost recovery mechanism.
    • Participating intermittent resource program initiative
      The PIRP Initiative focuses upon understanding the cost drivers for wind generation resources and if improving the forecast accuracy can significantly reduce cost impacts. It also includes development of a tariff filing to address the appropriate charges associated with the export of energy from Participating Intermittent Resources Program resources.
    • Pay for performance regulation
      FERC Order No. 755 required that the ISO modify the compensation mechanism for regulation to include a performance payment with an accuracy adjustment in addition to the existing capacity payment. The ISO has FERC approval of the proposed tariff modifications, and is conducting a one year evaluation of the methodology for calculating mileage accuracy and assessing whether the minimum performance standard and any additional items should be revised.
    • Real-time imbalance energy offset (2009)
      In response to inquiries by market participants regarding the real-time imbalance energy offset (Charge Code (CC) 6477) for the month of April, the California ISO conducted a review of the first monthly invoice published under the new market model launched April 1, 2009. The ISO seeks to discuss its findings with stakeholders. The imbalance energy offset is calculated by summing the settlement dollar values for the following charge codes: real-time instructed imbalance energy (CC6470), real-time uninstructed imbalance energy (CC6475), real-time unaccounted for energy (CC6474) and the Hour-Ahead Scheduling Process (HASP) energy, congestion and loss pre-dispatch (CC6051), less real-time congestion offset (CC6774). Consistent with Section 11.5.4.2 of the ISO Tariff, allocation of CC6477 is based on measured demand in pro rata share to all scheduling coordinators including Metered Sub-System operators that are not load following and have elected gross settlement.
    • Self-schedules bid cost recovery allocation and bid floor
      This initiative considers lowering the bid price floor and removing the exemption from day-ahead bid cost recovery allocation for load served by self-scheduled generation. These modifications will more accurately represent ISO market costs and allocate them based on cost-causation. They will also provide greater incentive for economic bidding and allow the market to more efficiently address over-supply conditions, which will be increasingly important as the resource fleet reaches a 50% renewable portfolio standard.
    • Seven-day advanced outage submittal
      California ISO Tariff Section 9.3.3 gives the ISO the authority to reject outages submitted in less than 72 hours but does not address rejecting outages submitted less than 7 days and greater than 72 hours. The ISO will propose tariff revisions that clarify when a transmission outage request must be submitted and provide criteria for accepting or rejecting outages that are submitted less than 7 days in advance of the outage start date. Submitting outage requests in advance will allow the ISO to complete needed analysis and provide approvals in time to comply with Western Electricity Coordinating Council (WECC) reporting requirements.
    • Temporary shutdown of resource operations
    • Transmission access charge options
      The current transmission access charge is a two-part rate for each megawatt hour of internal load and exports and is used to recover transmission revenue requirements. Revenue requirements for facilities rated 200 kV and above are recovered through a system-wide rate, while requirements for facilities rated below 200 kV are recovered via specific rates for each participating transmission owner. This initiative considers if the same structure would be appropriate should a transmission owner with a load service territory join the ISO as a participating transmission owner.
    • Uneconomic adjustment policy
      Formerly Parameter Tuning. The primary purpose of the Parameter Tuning effort is to determine the values for the various Uneconomic Adjustment parameters – i.e., the penalty prices – to be used in the MRTU market software at the start-up of the MRTU markets and in the final phase of Market Simulation leading up to the market start-up. There are several ways to classify the various penalty prices to be studied in this effort: (a) scheduling run parameters and pricing run parameters; (b) Self Schedule parameters and constraint parameters; and (c) Day Ahead Market parameters and Real Time Market parameters. As a result of the Uneconomic Adjustment Policy effort the California ISO (the ISO) anticipates making a filing at FERC in July to amend certain related provisions of the MRTU Tariff.
    • Valley Electric Association
      The California ISO and Valley Electric Association have executed a memorandum of understanding that will form the basis of a transition agreement, once authorized by the ISO Board of Governors, detailing the process for the electric cooperative to become an ISO participating transmission owner, utility distribution company and load serving entity. Valley Electric and the ISO have identified several integration issues that must be addressed prior to January 2013 when Valley Electric is expected to formally participate in the ISO market. This initiative is not following the normal ISO stakeholder process because of the nature of the negotiations between the ISO and Valley Electric.
    • Alternative dispute resolution committee tariff amendment
      The California ISO tariff places responsibility for administering and coordinating the ISO's process for alternative dispute resolution (ADR) with a committee of the Board of Governors. The committee is required to maintain lists of arbitrators and mediators, process and publish information about ADR activities and compile procedures for arbitration. The purpose of this stakeholder process is to consider a tariff amendment that would – consistent with the practices of other ISOs and RTOs – relieve the ISO Board of alternative dispute resolution responsibility and place it under management's supervision.
    • Bid cost recovery mitigation measures
      In December 2011, as part of Renewables Integration Market and Product Review Phase 1 initiative, the Board approved separating the day-ahead and real-time bid cost recovery calculations. Through this initiative we will design and implement a performance metric and a check for persistent uninstructed imbalances in the bid cost recovery calculation to mitigate any adverse effects.
    • Capacity procurement mechanism designation of Sutter Energy Center
      This stakeholder process is to receive comments on an ISO analysis of a request made by Calpine on Nov. 22, 2011 asking the ISO to designate its Sutter Energy Center as needed under the Capacity Procurement Mechanism (CPM). Without the designation, Calpine will retire the plant for economic reasons and any future repowering of the facility is highly unlikely. The ISO has determined that the plant is needed in the 2017-2018 period to meet reliability and operational needs in the ISO balancing authority. As a result, the ISO will ask the Federal Energy Regulatory Commission for a tariff waiver that would enable the Sutter plant to receive a CPM designation, however, the ISO commits to initiating a stakeholder process in 2012 that will develop a longer-term solution.
    • Data release and accessibility phase 2 - convergence bidding information release
      With the April 1, 2009 implementation of the California ISO new market system based on locational marginal pricing, stakeholders expressed a desire for the release of additional information enabling them to better understand market results and more effectively participate in the ISO markets. In response, the ISO is conducting a stakeholder process to explore the issue of data release and accessibility in ISO markets and to implement appropriate enhancements to its current data provision practices.
    • Energy Imbalance Market year 1 enhancements phase 1
      The ISO is proposing a series of Energy Imbalance Market (EIM) enhancements for FERC compliance, to meet commitments made during the original stakeholder process and to resolve issues identified during implementation. Phase 1 will focus on improvements that will facilitate NV Energy’s October 2015 entry into the market, which includes creating a greenhouse gas flag, cost based bid adder, bidding rules on external EIM interties and clarifying administrative pricing rules.
    • FERC Order No 764 market changes
      Through this stakeholder initiative, the ISO proposes a new 15-minute scheduling option in the real-time market to comply with FERC Order No. 764, which requires us to offer intra-hourly transmission scheduling. We will also explore implementing financially binding 15-minute schedule settlements, which will reduce barriers to integration of variable energy resources and address other identified market inefficiencies.
    • Generation interconnection process reform
      On December 11, 2007, the Federal Energy Regulatory Commission held a nationwide technical conference to address challenges affecting the current queue management process adopted by Order No. 2003 and to explore possible reforms. The California ISO, as well as other ISOs and RTOs across the country, identified issues hindering the efficient implementation of the current queue management process. As a result of the California ISO's participation at the technical conference, FERC expressed a desire for the California ISO to propose any necessary reforms by Spring 2008. In accordance with the FERC directive, the ISO is initiating a stakeholder process to evaluate potential queue management reforms. To the extent ISO Tariff changes are necessary to implement any identified reforms, the ISO anticipates seeking its Board of Governors approval prior to submission to FERC for acceptance.
    • Interconnection requirements review
      To maintain system reliability on an ongoing basis, changes are required to the ISO interconnection requirements to accommodate increasing amounts of variable generation. This initiative proposes modifications to the operating power factor, voltage control, disturbance ride through, and generation management parameters for asynchronous generators, such as wind and solar resources. These requirements will be incorporated in interconnection agreements, if approved by the Federal Energy Regulatory Commission (FERC), and will make the technical requirements for these variable generation technologies more consistent with those of conventional generators.
    • Load serving entity definition refinement
      This initiative will refine the tariff definition of Load Serving Entity to include entities that have been granted authority by state or local law, regulation or franchise to serve their own load directly through wholesale energy purchases.
    • Multi-stage generating unit modeling
      The California ISO is developing software functionality for modeling multi-stage generating units, such as combined cycle generating plants. These units pose particular challenges with modeling and dispatch because they have multiple configurations in which they can operate and forbidden regions in which they cannot operate. The ISO seeks to review with stakeholders the key policy issues that arise with modeling these units, and to maintain an open dialog as implementation of the multi-stage generating functionality goes forward. The ISO is developing rules for the transition costs specified in the multi-stage generating transition matrix. These mitigation rules to balance flexibility and prevent economic withholding are part of the Bidding and Mitigation of Commitment Costs stakeholder initiative.
    • NERC reliability standards
      On June 4, 2007, mandatory reliability standards adopted by the Federal Energy Regulatory Commission (FERC) and administered by the North American Electric Reliability Corporation(NERC) and the Western Electricity Coordinating Council (WECC) for the bulk power system will become effective. Instances of non-compliance with these standards can result in monetary penalties levied against the party causing the standard violation. As part of the standards implementation process, the California ISO and a stakeholder working group have developed clarifying tariff language and a pro forma agreement addressing both the allocation of compliance tasks and responsibilities between the California ISO and the transmission owners/operators, and the recovery of penalties stemming from non-compliance situations.
    • Payment acceleration project
      The ISO recognizes that the current payment calendar takes too long between trade date and market clearing and presents undue credit risk to market participation. This increased risk may hinder resource availability from out-of-state resources, challenge credit management and expose market participants to additional risk in the event of defaults or bankruptcies. The ISO plans to implement payment acceleration approximately 6 months after the Settlements and Market Clearing System go live. Payment acceleration would provide market clearing on an average of 30 days. Payment acceleration also opens the possibility of other significant settlement improvements, such as providing participants an increased dispute window, and implementing a sunset provision.
    • Real-time imbalance energy offset (2011)
      The ISO has observed an increase in the real-time imbalance energy offset, concurrent with the February 1 implementation of convergence bidding and the April 1, 2011 bid cap increase to $1000 per megawatt hour. Through this initiative, the ISO will evaluate both the drivers of the offset and potential rate design changes of the real-time imbalance energy offset (charge code CC 6477) currently described in Section 11.5.4.2 of the ISO tariff.
    • Small and large generator interconnection procedures
      The small generator interconnection procedures established the requirements for generators no larger than 20 megawatts to interconnect to the California ISO controlled grid. FERC’s Order No. 2006 issued May 12, 2006 required the ISO to standardize the terms and conditions of open-access interconnection service. The ISO recently experienced a significant increase in the number of small generation projects seeking interconnection. This increase revealed issues with the small generator interconnection procedures. The ISO initiated a stakeholder process to address these issues and revise the small generator interconnection procedures. In discussions to revise the procedures, the potential solutions highlighted impacts to the large generator interconnection procedures. The small and large generator interconnection procedures have interdependencies, such that any solution to one procedure impacts the other.
    • Transmission constraint relaxation parameter change
      Currently the ISO market software relaxes transmission constraints whenever the constraint’s shadow price hits a threshold of $5,000. When this occurs, high shadow prices and corresponding locational marginal prices, coupled with the reduced constraint limits, cause high real-time congestion offset costs. The ISO proposes reducing the threshold to $2,500 in the real-time market only, which will still allow for effective flow mitigation through market optimization.
    • Variable operations and maintenance cost review 2012
      On Mar 29, 2012 the ISO revised its default operations and maintenance cost adders, which represent the per-megawatt hour variable, non-fuel costs of running a generating unit at or above its minimum operating level. The ISO increased the number of adder values from two to ten to differentiate costs by technology for all generation resources participating in the market.
    • Amendment 60 implementation plan
      On November 11, 2007 the Federal Energy Regulatory Commission (FERC) issued an “Order on Rehearing” in the Amendment 60 proceeding in Docket ER04-835 (Rehearing Order). The Rehearing Order, among other things, confirmed FERC's earlier finding that “Must Offer” commitments to address the Miguel constraint should be treated as zonal, rather than local. In addition, FERC found that commitments to address the South of Lugo constraint should also be treated as zonal, rather than local.
    • Bidding and mitigation of commitment costs
      Shortly after the launch of its new market in April 2009, the California ISO undertook a two-phased approach for changing start-up and minimum load bidding restrictions in order to alleviate the excessive cycling of generating resources and to help generators recoup their commitment costs. Phase 1, implemented in July 2009, enabled generation owners to modify their start-up and minimum load elections and to switch between the registered and proxy cost options more frequently. Phase 2 was initially proposed to implement 1) frequent start-up and minimum load cost bidding and 2) a mechanism for use-limited resources to capture opportunity costs.
    • Capacity procurement mechanism replacement
      This initiative will design a capacity procurement mechanism to replace the current one that expires Feb. 16, 2016. The proposal will include a durable mechanism and market-based price for the ISO to procure capacity not designated for resource adequacy in order to meet reliability needs. The ISO plans to present a proposal to its Board of Governors in the first quarter of 2015.
    • Data release and accessibility phase 3 - market efficiency
      With the April 1, 2009 implementation of the California ISO new market system based on locational marginal pricing, stakeholders expressed a desire for the release of additional information enabling them to better understand market results and more effectively participate in the ISO markets. In response, the ISO is conducting a stakeholder process to explore the issue of data release and accessibility in ISO markets and to implement appropriate enhancements to its current data provision practices.
    • Energy Imbalance Market year 1 enhancements phase 2
      The second phase of the Energy Imbalance Market (EIM) enhancements initiative will address the potential of an EIM-wide transmission rate, flow entitlements for base and day-ahead schedules, the treatment of transfer limit congestion, market power mitigation of transfer limits, and bidding rules on external interties. The initiative also includes items that were discovered during EIM implementation.
    • Flexible capacity procurement
      The ISO will need sufficient flexible capacity to reliably operate the grid as additional variable resources come on line to meet the state's 33% renewable target. This initiative explores short and long-term changes to the ISO backstop procurement authority so the ISO can procure the upward and downward ramping capacity required to accommodate sudden output changes inherent in variable resources, such as wind and solar.
    • Generator contingency and remedial action scheme modeling
      This initiative focuses on required enhancements to the day ahead and real time markets to support generator contingencies. The final proposal should result in an economic dispatch that will respect all emergency limits after the loss of a generating unit alone or due to remedial action scheme operation without the need for out-of-market intervention.
    • Inter-SC trades oversight exemption
      The ISO proposes to exempt inter-scheduling coordinator trades as part of the products and services that it believes should not fall within the oversight of the pending Commodity Futures Trading Commission (CFTC) market regulation. If these trades are not excluded, the ISO market would need to comply with the full range of requirements imposed by the Commodity Exchange Act - a significant burden for the ISO and its market participants. This initiative seeks stakeholder consensus for the proposed exemption, which may or may not require a tariff modification.
    • Local market power mitigation enhancements
      In a Sept. 21, 2006 order, the Federal Energy Regulatory Commission required that by April 1, 2012 the ISO begin using bid-in demand rather than forecast demand in the market power mitigation calculations used to mitigate bids in the integrated forward market. This initiative will address this requirement as well as explore the potential impacts that incorporating convergence bids and demand response in the market would have on how bids are mitigated. The impacts of these two market features were discussed but not assessed during the convergence bidding design initiative.
    • Multi-stage generation enhancements
      The ISO implemented the multi-stage generation modeling functionality in December 2010 that optimizes the commitment and dispatch of generating units that have multiple operating configurations. Through analysis of commitment, dispatch and market outcomes for multi-stage generation resources, the ISO and stakeholders have identified potential refinements to the procedure. This initiative will lead to the design of the new multi-stage generation functionalities.
    • Non-generator resources in ancillary services market
      This stakeholder initiative is for compliance with FERC Order Nos. 719 and 890. FERC Order No. 719, Wholesale Competition in Regions with Organized Electric Markets, directs Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs) to allow demand response resources to participate in Ancillary Service (AS) Markets assuming the demand response resources are technically capable of providing the ancillary service within response times and other reasonable requirements adopted by the RTO or ISO. FERC Order No. 890, Preventing Undue Discrimination and Preference in Transmission Service, requires that non-generation resources such as demand response must be evaluated on a comparable basis to services provided by generation resources in meeting mandatory reliability standards, providing ancillary services and planning the expansion of the transmission grid.
    • Payment default allocation
      This initiative is to review with stakeholders whether current tariff provisions regarding payment default allocations should remain in effect, be modified or replaced. This is the ISO methodology for calculating market participant's percentage share of a payment default. The ISO is undertaking this initiative as agreed to by FERC settlement agreement Docket No. EL09-62 signed in 2011.
    • Real-time market / constraint enforcement
      The California ISO is proposing a modification to clarify the enforcement of constraints in the ISO market processes and the relationship of the Full Network Model to transmission constraints. The ISO proposes to make necessary clarifications to the Full Network Model function description as it relates to the ISO's transmission constraints enforcement in its market operations.
    • Standard capacity product phase I
      The California ISO acknowledges the need for a standardized Resource Adequacy (RA) capacity product to ensure efficiency and reliability in RA contracting and trading. The purpose of this initiative is to define and formalize a Standard RA Capacity Product (SCP) which is intended to simplify and increase the efficiency of the RA program. The ISO Market Initiative Roadmap process and resulting Final Report on Ranking of High Priority Market Initiatives (7/7/08) revealed that the SCP ranked highest out of over 70 initiatives. The ISO is responding to stakeholders in developing the SCP. Development and implementation of the SCP will require ISO Tariff revisions as well as approval by the ISO Board of Governors and the Federal Energy Regulatory Commission.
    • Transmission Maintenance Coordination Committee tariff amendment
    • Voluntary preferred resource auction
      This initiative will establish a voluntary annual auction for preferred resource capacity, which enables procurement of preferred resources to manage local areas affected by SONGS’ closure and to meet ISO reliability requirements. The phase one auction will match buyers to suppliers of demand response resources only for a multi-year term, while phase two will provide participation allowances for multiple resource types.
    • Ancillary services forced buy back
      The ancillary services forced buy back mechanism reduces ancillary service awards and self-provisions by the amount that is unavailable due to transmission constraints or plant limitations. Participants whose resources are subject to forced buy backs currently retain their capacity payments, which increases the cost of ancillary service procurements. This initiative seeks to align the settlement of ancillary services forced buy backs with existing rules of unavailable ancillary service capacity.
    • Bidding rules enhancements
      Through this initiative the ISO will evaluate the following: 1) unrestricted flexibility of resources to change energy bid prices between the day-ahead and real-time markets, and across real-time hours; 2) restrictions on commitment cost changes between and within the day-ahead and real-time markets; and 3) verification of generator resource characteristics. These proposals may require significant market design and system changes.
    • Capacity procurement mechanism risk-of-retirement process enhancements
      The ISO backstop procurement is currently limited to resources that do not receive a resource adequacy contract for the upcoming year. Resource owners believe this is a problem because they do not know whether they will have a contract until October 31 of the current year. This initiative will consider whether an analysis can take place prior to Oct. 31.
    • Deliverability for distributed generation
      The ISO is proposing a new annual assessment methodology for determining and allocating resource adequacy deliverability for distributed generation resources. Currently, the ISO determines distributed generation deliverability through assessments in the ISO generator interconnection cluster study process. Load serving entities use the deliverability results for their procurement of distribution-connected generation to meet resource adequacy requirements. The new assessment would run parallel to the generation interconnection procedures and be coordinated with the interconnection procedures and the transmission planning process. This initiative is in support of the Governor of California’s goal of 12,000 megawatts of distributed generation by 2020.
    • Energy Imbalance Market transition period
    • Flexible capacity requirements
      This initiative will establish an annual technical study process to determine the flexible capacity needed that guides resource adequacy procurements for 2015 and at least three years beyond.
    • Generator interconnection and deliverability allocation procedures reassessment
      This initiative will examine topics that arose following the first annual reassessment of the generation interconnection and deliverability allocation procedures. These topics include potential adjustments to cost caps and interconnection financial posting requirements resulting from a reassessment, and possible use of forfeited funds from interconnection customer project withdrawals to offset financial impacts on remaining customers in the queue and applicable participating transmission owners.
    • Intertie pricing and settlement
      Through this initiative the ISO is seeking long-term solutions to address the real time imbalance energy offset and pricing inefficiencies between the hour-ahead schedule process and real-time market. These issues were identified during the Real-Time Imbalance Energy Offset initiative and Price Inconsistency Caused by Intertie Constraints initiative. The primary focus of this stakeholder process is to find solutions to intertie pricing and settlement that reduce the real-time imbalance energy offset. The secondary objective of this initiative is to potentially provide a mechanism that allows convergence bidding at the interties.
    • Local market power mitigation enhancements 2015
      The initiative will explore planned and proposed changes to the market power mitigation process to address under-mitigation and potential over-mitigation in the fifteen-minute market, and to establish a predictive mitigation procedure in the five-minute market. These modifications can improve accuracy by ensuring that mitigation is applied when constraints will most likely be binding in real-time.
    • Multi-year reliability framework
      The staff of the ISO and the California Public Utilities Commission are developing a joint reliability framework for requiring multi-year procurement of backstop power that will complement existing resource adequacy obligations. This effort will recommend the needed revisions to the CPUC resource adequacy program and the ISO capacity procurement mechanism tariff provisions.
    • Operations and maintenance cost adder review and update
      As an outcome of the bidding and mitigation of commitment costs initiative (phase 2), the California ISO is initiating the first re-evaluation of the operations and maintenance cost adder used for proxy minimum load costs and default energy bids to make sure they still reflect resources’ variable operations and maintenance costs. The ISO will communicate the study methodology and resulting recommendations for updated operations and maintenance values through a stakeholder implementation forum and stakeholders will have the opportunity to provide comments. The first update to the default operations and maintenance cost adder is targeted for implementation on April 1, 2012. Re-evaluations take place every three years.
    • Peak reliability coordinator funding
      In 2014, the Western Electricity Coordinating Council transferred its reliability function to a new independent entity called Peak Reliability. As a result of the change, the ISO will now receive a reliability coordinator services bill from Peak Reliability. This initiative will address changes to the ISO settlement and payment processes necessary to pass the reliability coordinator charges to market participants. The new funding approach will begin with the 2016 budget, with annual invoices to the funding parties issued in November 2015 for payment in early January 2016.
    • Reducing exceptional dispatch
      Reliability requirements that cannot be resolved through the California ISO market software are met by manually issued Exceptional Dispatches. The ISO is committed to reducing reliance on Exceptional Dispatch to the extent possible. The ISO has initiated this stakeholder process to assess with stakeholders the reasons underlying Exceptional Dispatch and address what appropriate modeling or software solutions and/or market products may be developed to reduce the need for Exceptional Dispatch going forward that will and reduce reliance on Exceptional Dispatch to situations that are rare and infrequent or genuine emergencies.
    • Standard capacity product phase II
      Effective Jan. 1, 2010 the ISO implemented the Resource Adequacy (RA) Standard Capacity Product (SCP) as approved by FERC. Certain RA resources were temporarily exempt from the SCP standards; however FERC directed the ISO to work with stakeholders, the CPUC and LRAs to effect changes so that these exemptions could be removed. The ISO initiated the Standard Capacity Product Phase II (SCP II) effort to address this requirement.
    • Transmission planning and generator interconnection integration
      The objective of this initiative is to integrate some components of the transmission planning and generator interconnection procedures so that ratepayer-funded transmission additions and upgrades are identified and approved under a single comprehensive process. The new process will provide incentives for resource developers to interconnect to the ISO grid at the most cost-effective locations. This effort builds on the FERC-approved revised transmission planning process, the generator interconnection procedures enhancements and generator interconnection Phase 2 discussions.
    • Wheeling data submission tariff amendment
      The California ISO has initiated this stakeholder process to consider amending Section 26.1.4.4 of its tariff. This section currently requires scheduling coordinators to submit wheeling data for transactions between the ISO controlled grid and a non-participating transmission owner's transmission system "within five days from the end of the calendar month to which the relevant Trading Day relates". The ISO proposes to amend the tariff section to require submission of wheeling transaction data within 43 calendar days from the trading day on which the wheeling transaction occurs.
    • Ancillary services procurement in HASP and dispatch logic
      To prepare for the new market launch, the California ISO filed and received approval from the Federal Energy Regulatory Commission (FERC ) to defer the procurement of ancillary services in hour-ahead scheduling process (HASP), and to procure any required incremental ancillary services after the day-ahead market in the 15-minute Real-Time Pre-Dispatch (RTPD) process. The ISO submitted the Deferred Function Amendment Filing to FERC on October 31, 2008, and indicated that it anticipated reverting back to hour-ahead procurement of ancillary services six to nine months after the new market go-live. Under this initiative, the ISO considers reverting to ancillary services procurement in HASP and proposes solutions to dispatch energy from operating reserves procured from non-dynamic system resources in the hour ahead.
    • Blackstart and system restoration
      The ISO proposes tariff amendments to incorporate a new pro-forma blackstart agreement that complies with a revised blackstart resource definition and mandatory reliability standards recently approved by FERC, which become effective July 1, 2013. All generators included in the power restoration plan will be subject to the new standardized agreement. The ISO will also remove related tariff references that will no longer be applicable.
    • Central counterparty exception for self-supply
      The ISO filed tariff revisions in compliance with FERC Order No. 741 to become a central counterparty effective Sept. 1, 2012. This initiative proposes a limited exception to the ISO status as a central counterparty to address concerns raised by a number of municipal utilities that it could jeopardize the tax-exempt status of their bonds.
    • Deliverability of resource adequacy capacity on interties
      The ISO methodology for determining the intertie capacity needed to accommodate resource adequacy supplies currently uses only historical data. This methodology ignores planned capacity upgrades, which can result in interties having a very low or zero capacity value. The ISO is initiating a stakeholder process to explore alternative methodologies for determining the resource adequacy intertie capacity and to consider ways of reducing import barriers for resources developing outside the California ISO.
    • Energy storage interconnection
      This initiative will examine issues with connecting energy storage facilities to the ISO controlled grid under the existing rules, and will develop new policies as needed to clarify and facilitate interconnection of energy storage.
    • Flexible ramping constraint
      Implementation of a new flexible ramping constraint in the market optimizations will help ensure sufficient ramping capability is available to meet conditions in the five-minute market interval when conditions have changed from the assumptions made during the prior procurement procedures. Enforcement of the constraint can produce opportunity costs for resources that resolve the constraint. Through this initiative the ISO and stakeholders will address how to appropriately compensate resources that resolve the constraint.
    • Generator interconnection driven network upgrade cost recovery
      The ISO tariff requires Participating Transmission Owners (PTOs) to reimburse generator interconnection customers for certain network upgrades. These network upgrade costs are included in their customer rate bases through transmission access charges. Customers of PTOs with a relatively small rate bases could experience significant rate increases from generator driven low voltage network upgrades. This initiative will explore potential changes to the current network upgrade cost recovery mechanism.
    • Location constrained resource interconnection policy
      On January 25, 2007 the California ISO (the ISO) filed a Petition with FERC for a Declaratory Order seeking conceptual approval of a new financing mechanism to facilitate the construction of interconnection facilities for location-constrained resources. On April 19, 2007, FERC granted the ISO's petition and accepted the design concepts proposed therein, thereby paving the way for the ISO to file tariff language for implementing this important initiative. The purpose of the Remote Resource Interconnection (RRI) initiative is to further develop the policy details with the expectation of developing tariff language to be filed with FERC no later than October 31, 2007.
    • Outage management system replacement
      The ISO will replace its existing outage management system with one that has enhanced modeling capabilities and simplifies our business processes to improve the accuracy and efficiency of managing outages. The system is targeted for implementation in October 2014, at which time the Scheduling and Logging for ISO of California (SLIC) application will no longer be used for managing outages.
    • Penalty allocation procedure tariff amendment
      The ISO is proposing draft tariff language on the process it intends to follow when seeking authority from the Federal Energy Regulatory Commission to allocate the cost of any monetary penalties that regulatory bodies impose. The proposed procedure follows FERC’s guidance in its Order Providing Guidance on Recovery of Reliability Penalty Costs by Regional Transmission Organizations and Independent System Operators.
    • Regional integration and EIM greenhouse gas compliance
      This initiative explores mechanisms to track compliance obligations with California greenhouse gas regulations for supply resources located outside of California in an expanded balancing authority area. This initiative will also examine similar mechanisms for resources participating in the Energy Imbalance Market (EIM).
    • Standard capacity product temporary waiver
      This initiative is to refine the rules for an issue remaining from the 2009-2010 standard capacity product stakeholder process. This effort will determine the appropriate forced outage reporting rules for Qualifying Facilities that are grandfathered from SCP availability payments and charges. Initially, the ISO will submit a request to FERC for a temporary waiver from outage reporting obligations followed by a stakeholder process to resolve the underlying issue.
    • Transmission reliability margin
      Currently, the ISO implements certain adjustments to intertie schedules within operating hours. Using a mechanism known as Transmission Reliability Margin, the ISO will be able to anticipate these transmission constraints in advance by reflecting them in market processes before schedules are awarded in the hour-ahead scheduling process. In this initiative, the ISO will develop tariff revisions and the NERC-required transmission reliability margin implementation document. The document will provide greater clarity regarding ISO management of transmission constraints in the real-time market.
    • Approval of transmission elements under $50 million
      The tariff allows ISO management to approve transmission projects expected to cost less than $50 million that are identified in the annual planning process. The ISO proposes to extend its tariff provisions to also include any transmission elements under $50 million. This will enable the ISO to conduct competitive solicitations for smaller, needed transmission elements on accelerated timelines and avoid delays caused by trying to meet the Board of Governors approval process.
    • Black start and system restoration phase 2
      The ISO recently identified a need for immediately procuring additional black start resources beyond those already procured by transmission operators. This initiative will examine cost allocation for incremental black start resources, and address issues associated with additional black start resource procurement.
    • Circular scheduling
      Circular scheduling occurs when the power scheduled for export from the source balancing authority returns back to the original scheduled import point and no power actually flows (source and sink remain the same). A market participant can unduly profit from this practice while creating potential operational issues arising from a mismatch between scheduled versus actual flows. Following stakeholder discussion, the ISO will consider clarifying existing market rules.
    • Demand response initiative
      The ISO is actively engaged with stakeholders in developing viable wholesale demand response products with direct market participation capability. Products that can be provided by non-generation resources, such as demand response, can be used for power system reliability.
    • e-Tagging timing requirements
      e-Tag timing requirements have been highlighted as an issue in several stakeholder initiatives such as Convergence Bidding. The California ISO currently requires an e-tag no later than T-20 after adjustments in Hour-Ahead Scheduling Process (HASP). The large majority of market participants have voluntarily tagged Integrated Forward Market (IFM) awards prior to HASP. Several market participants have expressed concern that not requiring an e-tag for IFM awards prior to HASP can lead to implicit virtual bidding at interties and the feasibility of Day-Ahead schedules may be at risk.
    • Flexible ramping product
      In August 2011, the California ISO Board of Governors approved the flexible ramping constraint interim compensation methodology. At that time the ISO committed to begin a stakeholder initiative to evaluate the creation of a flexible ramping product that will allow the ISO to procure sufficient ramping capability via economic bids. Through this initiative, the ISO will evaluate allocating costs to generation and load in accordance with cost causation principles.
    • Pool of bids in the integrated forward market
      This initiative modified a current market rule which limits the pool of bids considered in the Integrated Forward Market (IFM) to resources that are dispatched in the Local Market Power Mitigation procedures run prior to the IFM (ISO Tariff Section 31.2). The ISO is considering three options on this market rule: 1) maintain the rule but continue to monitor market impacts under different market conditions; 2) modify tariff/BPM to give ISO operators the option of relaxing the rule if it is significantly impacting IFM results; or 3) modify tariff to require consideration of all bids in IFM.
    • Stepped constraint parameters review
    • Commitment cost enhancements phase 1
      The ISO implemented tariff changes that: 1) allow the ISO, in the event of a significant price spike, to execute and settle the market using a gas price published on the morning of the day-ahead market run rather than the prior evening’s calculated gas price index; 2) increased the existing proxy cost bid cap from 100 percent of the resource’s calculated proxy cost to 125 percent; and 3) eliminated the registered cost option for all resources except use-limited resources. FERC directed the ISO to submit an informational report concerning the impact of these changes on longer term market design changes for commitment costs by Aug. 1, 2015.
    • Demand response net benefits test
      FERC Order No. 745 requires the ISO to implement a net benefits test that establishes a price threshold above which demand response resource bids are deemed cost effective. The ISO must perform a monthly analysis based on historical data from the previous year’s supply curve to identify the price threshold estimate that shows where customer net benefits occur. The ISO must submit supporting documentation to its associated tariff revisions to FERC by July 22, 2011.
    • Ex post price correction make whole payments
      Ex post price corrections have led to instances in which bids that were cleared in the market are no longer economical when evaluated against the corrected price. Currently, the ISO does not have a policy or mechanism for compensating market participants when this occurs. The absence of such a make-whole mechanism was based on the assumption that the need for market results would always be consistent with the cleared bids. In practice, this is generally the case. When market prices require corrections, however, settlement prices can differ from the value of the cleared bids. Through this initiative, the ISO will develop a make-whole payment mechanism to compensate market participants for adverse financial impacts in the case when prices are adjusted in a way that is not consistent with their accepted bids.
    • Flexible resource adequacy criteria and must offer obligations
      This initiative will explore further enhancements to flexible capacity requirements to help address generation oversupply and ramps less than three hours. This effort also seeks new rules to allow intertie resources and storage resources’ not operating under non-generator resource provisions to provide flexible capacity. Through this effort we will also assess the impact of merchant variable energy resources on flexible capacity requirements.
    • Generator interconnection procedures cluster 1 and 2 deliverability concerns
      A number of stakeholders have raised concerns that the long development timelines and high costs of network upgrades in adjacent PTO service territories identified for certain Cluster 1 and 2 generation interconnection projects will impede the commercial viability of these projects. The identified need for these upgrades is related to the high volume of generation that was included in the Cluster 1 and 2 phase 2 studies.
    • Post emergency bid cost recovery filing review
      The ISO made two emergency filings with FERC in the first half of 2011 to mitigate observed adverse market behavior. Several strategies were being employed that aimed to expand uplift payments. The ISO committed to conducting a process for stakeholders to comment and raise any further changes or refinements to proposed tariff amendments. The ISO has opened this initiative as a forum for stakeholders to discuss market behavior that expands bid cost recovery uplift payments and develop rule changes if necessary needed to address such behavior.
    • Regional resource adequacy
      Resource Adequacy (RA) is a mandatory planning and procurement process to ensure adequate resources to serve all customers in real time. The program requires that Load Serving Entities (LSEs) meet a Planning Reserve Margin for their obligations. The program provides deliverability criteria that each LSE must meet, as well as system and local capacity requirements. Rules are provided for "counting" resources towards meeting resource adequacy obligations. The resources that are counted for RA purposes must make themselves available to the California ISO for the capacity for which they were counted. The ISO's Interim Reliability Requirements Program and the resource adequacy under MRTU tariff provisions are intended to complement the State of California's efforts to implement resource adequacy programs.
    • Commitment cost enhancements phase 2
      On Nov. 1, 2016, the ISO implemented tariff and policy changes to clarify the transition cost calculation definition and provide guidelines on how it will be calculated.
    • Demand response - proxy demand resource
      The ISO proposes the proxy demand resource product in order to increase demand response participation in the ISO market and respond to stakeholders’ requests for a demand response product that will facilitate the participation of existing retail demand programs in the ISO market.
    • Exceptional dispatch
      Under MRTU, reliability requirements that cannot be resolved through the California ISO market software will be met by manually issued Exceptional Dispatches. Units receiving Exceptional Dispatches for energy will be paid the higher of their bid price or the Locational Marginal Price (LMP). The ISO expects that the frequency and duration of Exceptional Dispatches will be very limited under MRTU. However, the potential cost of such Exceptional Dispatches could be significant if generators receiving such dispatches are able to exercise local or temporary market power by submitting extremely high energy bids. Therefore, the ISO is considering modifications to the MRTU to mitigate the potential for market power by units receiving Exceptional Dispatches for energy.
    • Frequency response phase 1
      This initiative will explore how to ensure acceptable dynamic response to frequency changes during the initial seconds to one minute following a large disturbance, which is critical for system reliability. Frequency response is provided by turbines and frequency responsive load. The system’s ability to respond sufficiently and quickly protects equipment by limiting the magnitude of the disturbance.
    • Generator interconnection procedures phase 2
      On Dec. 16, 2010, the Federal Energy Regulatory Commission conditionally approved tariff provisions to the generator interconnection process known as Generator Interconnection Procedures. In phase 1, these new procedures combined the small and large interconnection process into a single cluster approach and streamlined the timelines under the study process. Phase 2 addresses carryover issues from Phase 1 and other issues that encompass generator technical specifications, information accessibility, non-conforming large generator interconnection agreement provisions, study assessment methodology and posting requirements.
    • Post five-day process price corrections
      Since the start of the new California ISO market design on April 1, 2009, there have been isolated instances in which market prices were corrected outside of the five-day Price Correction Time Horizon. The ISO has not previously published the criteria used to evaluate whether a price correction is warranted after the expiration of the Price Correction Time Horizon. Through this initiative, the ISO will work with stakeholders to determine the circumstances under which post five-day price corrections may be made.
    • Regulatory must-take generation
      The ISO plans to revise its tariff definition of regulatory must-take generation related to combined heat and power resources to make it more applicable to facilities capable of producing electricity in conjunction with their industrial processes and thermal energy uses. The new definition will allow combined heat and power resources to establish a capacity level eligible for regulatory must-take generation scheduling priority even though the resource is no longer subject to a grandfathered power purchase agreement. The ISO will also clarify that once grandfathered power purchase agreements have terminated resources will be required to comply with the ISO tariff. Current policy exempts facilities with grandfathered power purchase agreements from complying with the ISO tariff.
    • Commitment cost enhancements phase 3
      Effective April 1, 2019, the ISO activated system changes to calculate use-limited resource opportunity costs and create opportunity cost adders for bidding into the ISO market using the proxy cost option. Effective May 1, 2019, the calculated Opportunity Cost Adders are available for use in the ISO markets. This implementation improves the management of use limited resources by allowing translation of most cases into standard limitations, therefore reducing the amount of cases requiring negotiation of opportunity costs.
    • Distributed load reference bus
      The ISO is proposing a modification to certain language in Appendix C of its tariff describing the calculation of Locational Marginal Prices (LMPs). Specifically, the ISO proposes a minor modification to the provisions regarding the designation of a Reference Bus as it pertains to the calculation of the marginal cost of energy. The ISO Tariff currently provides that the ISO will use a distributed load Reference Bus in calculating the marginal cost of energy. If accepted for filing, this amendment will explicitly clarify that the ISO has the flexibility to use a distributed generation Reference Bus as a backstop measure in cases where the Integrated Forward Market (IFM) cannot clear using a distributed load Reference Bus.
    • Exceptional dispatch mitigation in real time
      The local market power mitigation phase 2 initiative, which is conducted in parallel with this initiative, will implement a dynamic competitive path assessment that flags paths as uncompetitive based on the amount of congestion present on the lines under review, and determines the triggers for exceptional dispatch mitigations. This initiative seeks to complement those changes by implementing a mechanism to identify and mitigate for exceptional dispatches that have local market power and create a set of default path designations to use should the dynamic assessment fail to produce a valid set of designations. The exceptional dispatch mitigation in real time tariff changes are being addressed in the local market power mitigation FERC filing
    • Full network model expansion
      Through this initiative, the ISO will expand its full network model to more effectively balance the grid with external balancing authority areas and improve reliability and market solution accuracy, consistent with FERC and NERC recommendations following the September 8, 2011 southwest power outage. The proposed solution includes enhanced 1) loop flow modeling; 2) security analysis; 3) high voltage direct current transmission modeling; and 4) outage analysis and coordination.
    • Generator interconnection procedures phase 3
      The ISO has deferred this initiative and will instead focus its efforts on generator project downsizing through a separate initiative based on stakeholder comments and priorities. A revised Phase 3 schedule will be announced later in 2012.
    • Price corrections for invalid congestion
      In January 2013, a software defect in the real-time market application did not accurately reflect certain intervals of prices for congestion observed in the Birds Landing area. The ISO will analyze the market impact to determine if good cause exists to seek regulatory relief from FERC to waive Section 35.3 of the ISO Tariff, extending implementation of price corrections beyond the standard five-day window.
    • Reliability coordinator services rate design, terms and conditions
      This initiative will determine the necessary tariff changes to describe the rate, terms and conditions that support the ISO’s provision to become a Reliability Coordinator (RC), in compliance with federal and regional grid reliability standards. The ISO will follow its open and transparent stakeholder process with all interested balancing authorities and transmission operators in the Western Interconnection to discuss the proposed RC services.
    • Commitment costs refinement 2012
      Through this initiative, the ISO will evaluate several more opportunities to further improve the specification of start-up and minimum load costs. The ISO plans to weigh changes to the proxy minimum load cost option to consider the following: 1) costs due to the upcoming greenhouse gas “cap-and-trade” program in California; 2) costs associated with operational flow orders in the natural gas market; and 3) the cost of the grid management charge into minimum load costs. The ISO also will evaluate changes to the registered cost option cap for start-up and minimum load costs, a fixed adder to proxy start-up calculations to cover major maintenance expenses, and additional issues related to commitment costs as requested by stakeholders.
    • Dynamic transfers
      During this stakeholder process we will review the range of dynamic transfer-based services presently offered in the ISO tariff, explore the issues central to the potential expansion of ISO dynamic transfer scheduling policy, and determine any appropriate tariff changes. Areas of potential future expansion of these services include: 1) Expanded use of dynamic import service for conventional resources to include dynamic transfer of intermittent or “renewable” energy resources into the ISO from other Balancing Authority Areas (BAAs), 2) Expansion of present dynamic scheduling functionality to include dynamic export service in the ISO tariff, including renewable energy and/or ancillary services from the ISO to other BAAs, 3) Incorporation of pseudo tie service in the ISO tariff, predicated upon the successful culmination of the two present conventional resource pseudo tie pilots, and 4) Extension of pseudo tie service to include intermittent resources. Outcome The ISO tariff revisions were approved by FERC on September 30, 2011. All changes not requiring software modification were made effective immediately. Dynamic Transfers policy was revised and approved by the Board of Governors with the FERC Order No. 764 Market Changes proposal on May 15, 2013. Dynamic transfer changes requiring market software modification implemented with the FERC Order No. 764 Market Changes stakeholder initiative.
    • Expanding metering and telemetry options
      As requested by participants, the ISO is evaluating additional configuration options for metering and telemetry to reduce barriers for aggregated resource models. We will conduct pilot programs as needed to demonstrate that the alternatives meet ISO and participant needs, and review and modify ISO requirements if necessary. The initiative may produce Business Practice Manual for Telemetry and Metering updates and potential tariff changes.
    • Generator project downsizing
      This initiative will explore additional opportunities for customers in cluster 4 and earlier in the generator interconnection study queue to downsize the capacity of their projects.
    • Price inconsistency caused by intertie constraints
      Upon the start of convergence bidding, the ISO began enforcing two separate constraints at each intertie scheduling point within the integrated forward market, pursuant to ISO tariff section 31.8. The constraints prevent virtual bids from causing net interchange schedule violations of intertie scheduling limits. Enforcing the separate constraints has resulted in a difference between export pricing and the resources’ bid price. As a result, export schedules are sometimes subject to prices above submitted bid prices. Through this stakeholder initiative, the ISO will evaluate the existing market rule and consider any changes to address adverse outcomes resulting from the current design.
    • Reliability demand response product
      The Reliability Demand Response Product (RDRP) is a wholesale demand response product that enables compatibility with, and integration of, existing retail emergency-triggered demand response programs into the California ISO market and operations. This includes newly configured demand response resources that have a reliability trigger and desire to be dispatched only under particular system conditions.
    • Commodity Futures Trading Commission related initiatives
      The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2012 expanded the authority of the Commodity Futures Trading Commission (CFTC) in a way that could be interpreted to cover certain transactions in ISO and RTO markets. The ISO is working with stakeholders through these initiatives to clarify and implement any changes required by the Act.
    • Expedited GIDAP enhancements 2017
      The ISO has identified two interconnection issues that need expedited resolutions: 1) how long an interconnection customer may “park” for purposes of receiving a Transmission Plan Deliverability allocation; and 2) how long interconnection customers have to submit, correct, and re-submit new interconnection requests within the ISO validation timeframe. Through this initiative the ISO proposes to change the current parking and interconnection request window and validation processes in the Generator Interconnection and Deliverability Allocation Procedures (GIDAP).
    • Price inconsistency market enhancements
      The ISO is seeking long-term solutions to address price inconsistencies occasionally produced in the ISO market when market solutions result in prices that do not cover the awarded bid prices. These inconsistencies can expose market participants to uneconomical awards and uncertain risks. Through this initiative we seek to: 1) develop enhancements that would reduce or eliminate root causes of price inconsistencies or 2) implement settlement mechanisms to make resources whole to their bid prices.
    • Reliability must-run pump load
      The ISO seeks to create a new Integrated Forward Market scheduling priority class for pumping load with regulatory must-run requirements that no longer are protected by existing transmission contracts. The new class will ensure that these pumping load schedules are not curtailed unless there is a system contingency affecting physical transfer of energy to the pumping facilities or ISO system demand cannot be met due to a severe energy supply shortage. — This stakeholder process was suspended March 2011 to address policy constraints relevant to this initiative.
    • Extended short term unit commitment
      This initiative will increase the time horizon used in the Short Term Unit Commitment (STUC) process for the real-time market. This will enable STUC to see system needs over a greater length of time and therefore more efficiently commit units as necessary.
    • Pricing enhancements
      This initiative includes the scope of the administrative pricing rules initiative plus additional pricing enhancements for improving ISO market efficiency. Through this stakeholder process we will examine tariff provisions regarding market intervention during significant system emergencies and settlement of force majeure events. We also seek enhancements to address multiplicity of prices, compounded congestion due to multiple concurrently binding contingencies and schedule priorities for existing transmission rights.
    • Reliability services
      The purpose of this initiative is to create an efficient and durable market mechanism for backstop capacity procurement, develop necessary conforming changes to resource adequacy processes, and enhancing rules specific to Resource Adequacy resources. During Phase 2, the ISO will finalize replacement and substitution rules for flexible and local capacity resources, as well as clarify processes and timelines for ISO default resources adequacy rules and effective flexible capacity calculations.
    • Competitive solicitation process enhancements
      This initiative is the latest in a series of stakeholder processes conducted over the past several years to review and improve the Phase 3 competitive solicitation procedures of the ISO transmission planning process. The ISO and stakeholders will use lessons learned from the 2012-2013 process to identify potential enhancements that improves the efficiency and effectiveness of the process.
    • Proposal to eliminate operational review tariff provision
      This stakeholder process seeks stakeholder input on elimination of section 22.1.2.2 of the ISO tariff, which requires that the ISO conduct an annual operational review. Given the maturity of the ISO compliance and audit functions and the NERC and WECC compliance structure the ISO has concluded that this annual review has been supplanted and is no longer needed.
    • Renewable integration market and product review phase 1
      While protecting system reliability, state policy requires the ISO integrate more renewable energy into California's wholesale energy market. Renewable resources operate with inherent output variability, making forecasting an important and challenging consideration. Further, renewables integration requires additional operational capabilities, including additional ramping support and ancillary services and increased ability to manage over-generation conditions. Renewable energy also imposes new operating requirements, such as more frequent starts and stops and cycling of existing generation units. The ISO wholesale market redesign in 2009, along with additional planned changes for 2010-2011, improve the ISO's ability to optimize the use of existing resources and generate market-driven prices that support investment in renewable resources. The ISO is confident that the system is capable of supporting 20% renewables integration. However, as we move toward 33% RPS, we need to examine further market design changes.
    • Competitive transmission improvements
      This initiative will consider improvements that support competition in the ISO transmission planning process for approved project sponsors who are non-participating transmission owners. The ISO is also proposing a new project sponsor application deposit to help mitigate costs incurred while performing and administering the competitive solicitation process.
    • Renewable integration market and product review phase 2
      The ISO and stakeholders are examining a range of measures that would adapt the wholesale energy markets to meet the operational requirements of renewable resources. A number of significant market and operational changes may be required depending on the megawatt quantity of renewable production as well as the particular mix of renewable resources and their locations. Given anticipated market and operational impacts, the ISO will consider as part of this initiative: near-term changes to existing market design that may provide the ISO with additional operational flexibility, and longer term market design changes in the form of new spot market and forward capacity products that will provide the needed operational characteristics from the conventional fleet for the ISO to reliably and cost-effectively integrate variable energy resources. — This initiative provides a long-term roadmap for market enhancements that will be updated through 2020 under various other initiatives.
    • Congestion revenue rights clawback rule modification
      The Congestion Revenue Rights (CRR) rule treats a day-ahead intertie award that is reduced in real-time as a “virtual award.” If the real-time reduction to a day-ahead intertie award exceeds 10% of the transmission capacity, then 100% of revenues on the CRRs are clawed back, discouraging rebidding into the 15-minute market. This initiative will explore which transactions should be considered “virtual awards” subject to clawback.
    • Renewable resources integration
    • Congestion revenue rights initiative - 2004-2006
      FERC's approval of the Feb. 2006 tariff filing in support of the California ISO's new market design, and several subsequent filings and associated orders, established the policy for Congestion Revenue Rights in the ISO's current market. The ISO has released short-term and long-term CRRs for the start of its new market design through the allocation and auction processes for CRRs that have been in effect since April 1, 2009. The ISO is now conducting both annual and monthly CRR allocation and auction processes for the release of prospective CRRs. Experience with these production related activities has allowed the CAISO to propose new initiatives to further improve our processes.
    • Replacement requirement for scheduled generation outages
      The California Public Utilities Commission will eliminate its resource adequacy replacement rule starting in 2013. At the request of the commission, the ISO will explore what market rule and tariff changes are needed to ensure that load serving entities and suppliers replace their committed resource adequacy capacity that is unavailable because of a scheduled outage.
    • Congestion revenue rights initiative - 2007
    • Residual unit commitment procedure in market redesign technology upgrade
      The California ISO is gathering additional data to investigate the causes of Residual Unit Commitment (RUC) availability prices seen in Market Redesign and Technology Upgrade (MRTU) market simulation to determine whether or not changes are necessary to the current RUC process prior to MRTU start-up.
    • Congestion revenue rights initiative - 2008
    • Resource adequacy availability incentive mechanism
      This expedited initiative identified settlement issues following the implementation of the Resource Adequacy Availability Incentive Mechanism (RAAIM). Through this initiative the ISO is proposing calculation modifications to correct the issues.
    • Congestion revenue rights initiative - 2009
    • Resource adequacy initiative
      Resource Adequacy (RA) is a mandatory planning and procurement process to ensure adequate resources to serve all customers in real time. The program requires that Load Serving Entities (LSEs) meet a Planning Reserve Margin for their obligations. The program provides deliverability criteria that each LSE must meet, as well as system and local capacity requirements. Rules are provided for "counting" resources towards meeting resource adequacy obligations. The resources that are counted for RA purposes must make themselves available to the California ISO for the capacity for which they were counted. The ISO's Interim Reliability Requirements Program and the resource adequacy under MRTU tariff provisions are intended to complement the State of California's efforts to implement resource adequacy programs.
    • Congestion revenue rights 2009-2010 enhancements
      In conducting its annual and monthly Congestion Revenue Rights allocation and auction processes for release of prospective CRRs, the ISO has identified credit and non-credit issues as candidates for further refinements. The ISO is revising the current credit requirements for CRR auction participation to improve the ISO’s credit coverage and efficiency of collateral usage and to facilitate participation in the auctions. The ISO is resolving the following non-credit issues: • Revise load migration process • Revise modeling and treatment of trading hubs in CRR allocation • Eliminate multi-point CRRs from CRR design • Add a weighted least squares objective function • Refine tiers in monthly allocation
    • Resource adequacy one-for-many manual substitution
      Scheduling coordinators can substitute capacity for resource adequacy resources on forced outages to avoid potential availability shortfalls. The ISO is developing automated functions to resolve current system limitations preventing the substitution of a single resource for more than one resource on outage. Until the solution is deployed, the ISO proposes a manual process to accommodate this one-for-many substitution under a limited set of conditions.
    • Congestion revenue rights 2011 enhancements
      Congestion Revenue Rights (CRRs) are financial instruments that enable market participants to manage the risks associated with congestion costs in the energy market. The purpose of the 2011 CRR Enhancements initiative is to streamline current processes, which includes simplifying load migration, improving revenue adequacy, streamlining allocation to load, and addressing minor issues that require tariff clarification.
    • Resource transitions
      The purpose of this initiative is to develop ISO Business Practice Manual (BPM) provisions for how the ISO will establish a Resource Adequacy (RA) deliverability status when a resource transitions from outside to inside the ISO balancing authority due to a change to 1) the resource's interconnection point, or 2) the ISO balancing authority boundary. These provisions will apply to resources that have previously supplied imported power but plan to establish a direct connection to the ISO grid as an internal resource. The existing ISO tariff and BPMs describe how to establish internal resource RA deliverability and how to allocate intertie RA deliverability to load-serving entities.
    • Congestion revenue rights tariff clarification 2012
      The ISO proposes tariff clarifications for Congestion Revenue Rights (CRR) processes concerning the priority nomination process, seasonal eligibility quantity calculations, secondary registration, CRR PNode retirement, and credit requirements for load migration and merchant transmission. Some of these changes will impact the upcoming 2013 annual CRR process. This initiative seeks to better align the tariff and business processes.
    • Review transmission access charge wholesale billing determinant
    • Consolidated Energy Imbalance Market initiatives
      This new initiative combines three EIM initiatives from the ISO 2017 Roadmap. The initiative will investigate if third party transmission owners located between two EIM balancing areas (BA) can provide available capacity to these entities for EIM transfers. It will also examine if current wheel through functionality can be used to manage bilateral schedule changes that either source or wheel across the EIM footprint. And finally, this initiative will explore equitable sharing of benefits when an EIM transfer wheels through an EIM BA.
    • Consolidated Energy Imbalance Market initiatives
      This new initiative combines three EIM initiatives from the ISO 2017 Roadmap. The initiative will investigate if third party transmission owners located between two EIM balancing areas (BA) can provide available capacity to these entities for EIM transfers. It will also examine if current wheel through functionality can be used to manage bilateral schedule changes that either source or wheel across the EIM footprint. And finally, this initiative will explore equitable sharing of benefits when an EIM transfer wheels through an EIM BA.
    • Revised settlement statement and dispute timeline for T+35M
    • Revised transmission planning process
      To help achieve the state's 33% Renewables Portfolio Standards (RPS) target, the California ISO proposes to add a new category of transmission projects that will facilitate the necessary expansion of the electric grid to support renewable resource policy objectives, as well as a transmission project evaluation process that will use commercial interest tests and other criteria to determine whether projects are eligible to receive conditional or final approval by the ISO.
    • Contingency dispatch enhancements
      The ISO proposes to give dispatch priority during a disturbance control standard event to energy bids from resources providing operating reserves. Currently, the ISO dispatches energy in economic order and observes that resources providing operating reserves respond more accurately and quickly than energy-only resources. The proposed change reduces the risk of not recovering from a disturbance event due to insufficient response.
    • Revisions to price correction requirements
      The ISO recognizes the importance of using correct prices to settle the market and the need to weigh that against price certainty. Through this stakeholder initiative the ISO will explore price correction process improvements and clarify the scope, reasons and time horizon for making after the fact corrections.
    • Contingency reserve cost allocation
      This initiative will propose modifications to the cost allocation of contingency reserves. The initiative will seek to align the cost allocation with WECC’s new standard for calculating contingency reserve requirements for balancing authority areas effective October 1, 2014.
    • Convergence bidding
      Convergence (or virtual) bidding is a mechanism whereby market participants can make financial sales (or purchases) of energy in the day ahead market, with the explicit requirement to buy back (or sell back) that energy in the real time market. Virtual bids pressure day ahead and real time prices to move closer together, thus reducing the incentive for buyers and sellers to forgo bidding physical schedules in the day ahead market in expectation of better prices in the real time market. Under FERC's Sept., 2006 MRTU Order, the California ISO must implement convergence bidding within twelve months after the new ISO market startup. FERC's April 20, 2007 Order specifies that the ISO must file tariff language for the implementation of convergence bidding no later than 60 days prior to the one-year anniversary of the new market startup. Thus the ISO is seeking focused stakeholder input now to help develop the design for convergence bidding so that the necessary software features and business processes can be built to meet a reasonable implementation schedule.
    • Cost allocation guiding principles
      Through this initiative the ISO will develop a set of guiding principles on how to allocate market costs among market participants. Initially, we will apply the principles to the flexible ramping product currently under development. Later in 2012, through a follow-up initiative, we will holistically review cost allocation methodologies developed through multiple stakeholder initiatives over the past 18 months to ensure consistency with these guiding principles.
    • Interconnection process enhancements 2013
      The ISO implemented interconnection process enhancements that improved queue management, the fast track process, timing of transmission cost reimbursement, redistribution of forfeited funds to reduce the costs of certain network upgrades, and consistency of suspension definition between serial and cluster projects.
    • Interconnection process enhancements 2015
​

 

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