California ISO Planning Standards

FILED 03/27/19 04:59 PM A1903026

June 23, 2011

1 / 226 Table of Contents

I. Introduction

II. ISO Planning Standards 1. Applicability of NERC Reliability Standards to Low Voltage Facilities under ISO Operational Control 2. Combined Line and Generator Outage Standard 3. Voltage Standard 4. Specific Nuclear Unit Standards 5. Loss of Combined Cycle Power Plant Module as a Single Generator Outage 6. Planning for New Transmission versus Involuntary Load Interruption Standard

III. ISO Planning Guidelines 1. New Special Protection Systems

IV. Combined Line and Generator Unit Outage Standards Supporting Information

V. Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard Supporting Information

VI. Background behind Planning for New Transmission versus Involuntary Load Interruption Standard

VII. Interpretations of Terms from the NERC Reliability Standards and WECC Regional Criteria

2 / 226 I. Introduction

The California ISO (ISO) tariff provides for the establishment of planning guidelines and standards above those established by NERC and WECC to ensure the secure and reliable operation of the ISO controlled grid. The primary guiding principle of these Planning Standards is to develop consistent reliability standards for the ISO grid that will maintain or improve transmission system reliability to a level appropriate for the California system.

These ISO Planning Standards are not intended to duplicate the NERC and WECC reliability standards, but to complement them where it is in the best interests of the security and reliability of the ISO controlled grid. The ISO planning standards will be revised from time to time to ensure they are consistent with the current state of the electrical industry and in conformance with NERC Reliability Standards and WECC Regional Criteria. In particular, the ISO planning standards:

o Address specifics not covered in the NERC Reliability Standards and WECC Regional Criteria; o Provide interpretations of the NERC Reliability Standards and WECC Regional Criteria specific to the ISO Grid; o Identify whether specific criteria should be adopted that are more stringent than the NERC Reliability Standards and WECC Regional Criteria where it is in the best interest of ensuring the ISO controlled grid remains secure and reliable.

NERC Reliability Standards and WECC Regional Criteria:

The following links provide the minimum standards that ISO needs to follow in its planning process unless NERC or WECC formally grants an exemption or deference to the ISO. They are the NERC Transmission Planning (TPL) standards, other applicable NERC standards (i.e., NUC-001 Nuclear Plant Interface Requirements (NPIRs) for Diablo Canyon Power Plant and San Onofre Nuclear Generating Station), and the WECC Regional Criteria:

http://www.nerc.com/page.php?cid=2|20

http://www.wecc.biz/Standards/WECC%20Criteria/Forms/AllItems.aspx

Section II of this document provides additional details about the ISO Planning Standards. Guidelines are provided in subsequent sections to address certain ISO planning standards, such as the use of new Special Protection Systems, which are not specifically addressed at the regional level of NERC and WECC. Where appropriate, background information behind the development of these standards and references (web links) to subjects associated with reliable transmission planning and operation are provided.

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3 / 226 II. ISO Planning Standards

The ISO Planning Standards are:

1. Applicability of NERC Reliability Standards to Low Voltage Facilities under ISO Operational Control

The ISO will apply NERC Transmission Planning (TPL) standards, the NUC-001 Nuclear Plant Interface Requirements (NPIRs) for Diablo Canyon Power Plant and San Onofre Nuclear Generating Station, and the approved WECC Regional Criteria to facilities with voltages levels less than 100 kV or otherwise not covered under the NERC Bulk Electric System definition that have been turned over to the ISO operational control.

2. Combined Line and Generator Outage Standard

A single transmission circuit outage with one generator already out of service and the system adjusted shall meet the performance requirements of the NERC TPL standards for single contingencies (TPL002). Supporting information is located within Section IV of this document.

3. Voltage Standard

Standardization of low and high voltage levels as well as voltage deviations across the TPL-001, TPL-002, and TPL-003 standards is required across all transmission elements in the ISO controlled grid. The low voltage and voltage deviation guideline applies only to load and generating buses within the ISO controlled grid (including generator auxiliary load) since they are impacted by the magnitude of low voltage and voltage deviations. The high voltage standard applies to all buses since unacceptable high voltages can damage station and transmission equipment. These voltage standards are shown in Table 1.

All buses within the ISO controlled grid that cannot meet the requirements specified in Table 1 will require further investigation. Exceptions to this voltage standard may be granted by the ISO based on documented evidence vetted through an open stakeholder process. The ISO will make public all exceptions through its website.

Table 1 (Voltages are relative to the nominal voltage of the system studied) Normal Conditions (TPL- Contingency Conditions Voltage Deviation Voltage level 001) (TPL-002 & TPL-003) Vmin (pu) Vmax (pu) Vmin (pu) Vmax (pu) TPL-002 TPL-003 ≤ 200 kV 0.95 1.05 0.90 1.1 ≤5% ≤10% ≥ 200 kV 0.95 1.05 0.90 1.1 ≤5% ≤10% ≥ 500 kV 1.0 1.05 0.90 1.1 ≤5% ≤10%

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4 / 226 4. Specific Nuclear Unit Standards

The criteria pertaining to the Diablo Canyon Power Plant (DCPP) and San Onofre Nuclear Generating Station (SONGS), as specified in the NUC-001 Nuclear Plant Interface Requirements (NPIRs) for DCPP and SONGS, and Appendix E of the Transmission Control Agreement located on the ISO web site at: http://www.caiso.com/docs/09003a6080/25/a3/09003a608025a3bd.pdf

5. Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard

A single module of a combined cycle power plant is considered a single contingency (G-1) and shall meet the performance requirements of the NERC TPL standards for single contingencies (TPL002). Supporting information is located in Section V of this document. Furthermore a single transmission circuit outage with one combined cycle module already out of service and the system adjusted shall meet the performance requirements of the NERC TPL standards for single contingencies (TPL002) as established in item 1 above.

A re-categorization of any combined cycle facility that falls under this standard to a less stringent requirement is allowed if the operating performance of the combined cycle facility demonstrates a re-categorization is warranted. The ISO will assess re-categorization on a case by case based on the following:

a) Due to high historical outage rates in the first few years of operation no exceptions will be given for the first two years of operation of a new combined cycle module. b) After two years, an exception can be given upon request if historical data proves that no outage of the combined cycle module was encountered since start-up. c) After three years, an exception can be given upon request if historical data proves that outage frequency is less than once in three years.

The ISO may withdraw the re-categorization if the operating performance of the combined cycle facility demonstrates that the combined cycle module exceeds a failure rate of once in three year. The ISO will make public all exceptions through its website.

6. Planning for New Transmission versus Involuntary Load Interruption Standard

This standard sets out when it is necessary to upgrade the transmission system from a radial to a looped configuration or to eliminate load dropping otherwise permitted by WECC and NERC planning standards through transmission

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5 / 226 infrastructure improvements. It does not address all circumstances under which load dropping is permitted under NERC and WECC planning standards.

1. No single contingency (TPL002 and ISO standard [G-1] [L-1]) should result in loss of more than 250 MW of load. This includes consequential loss of load as well as load that may need to be dropped after the first contingency (during the system adjustment period) in order to position the electric system for reliable operation in anticipation of the next worst contingency. 2. All single substations of 100 MW or more should be served through a looped system with at least two transmission lines “closed in” during normal operation. 3. Existing radial loads with available back-tie(s) (drop and automatic or manual pick-up schemes) should have their back-up tie(s) sized at a minimum of 50% of the yearly peak load or to accommodate the load 80% of the hours in a year (based on actual load shape for the area), whichever is more constraining. 4. Upgrades to the system that are not required by the standards in 1, 2 and 3 above may be justified by eliminating or reducing load outage exposure, through a benefit to cost ratio (BCR) above 1.0 and/or where there are other extenuating circumstances. To better understand the potential impact of the updated “planning for new transmission versus involuntary load interruption” standard, this standard will be considered a guideline for the first year that it is in effect in order to get an inventory of stations and transmission elements not in compliance and a cost impact of bringing them into compliance.

III. ISO Planning Guidelines

The ISO Planning Guidelines include the following:

1. New Special Protection Systems

As stated in the NERC glossary, a Special Protection System (SPS) is “an automatic protection system designed to detect abnormal or predetermined system conditions, and take corrective actions other than and/or in addition of faulted components to maintain system reliability.” In the context of new projects, the possible action of an SPS would be to detect a transmission outage (either a single contingency or credible multiple contingencies) or an overloaded transmission facility and then curtail generation output and/or load in order to avoid potentially overloading facilities or prevent the situation of not meeting other system performance criteria. A SPS can also have different functions such as executing plant generation reduction requested by other SPS; detecting unit outages and transmitting commands to other locations for specific action to be taken; forced excitation pulsing; capacitor and reactor switching; out-of-step tripping; and load dropping among other things.

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6 / 226 The primary reasons why SPS might be selected over building new transmission facilities are that SPS can normally be implemented much more quickly and at a much lower cost than constructing new infrastructure. In addition, SPS can increase the utilization of the existing transmission facilities, make better use of scarce transmission resources and maintain system reliability. Due to these advantages, SPS is a commonly considered alternative to building new infrastructure in an effort to keep costs down when integrating new generation into the grid and/or addressing reliability concerns under multiple contingency conditions. While SPSs have substantial advantages, they have disadvantages as well. With the increased transmission system utilization that comes with application of SPS, there can be increased exposure to not meeting system performance criteria if the SPS fails or inadvertently operates. Transmission outages can become more difficult to schedule due to increased flows across a larger portion of the year; and/or the system can become more difficult to operate because of the independent nature of the SPS. If there are a large number of SPSs, it may become difficult to assess the interdependency of these various schemes on system reliability. These reliability concerns necessarily dictate that guidelines be established to ensure that performance of all SPSs are consistent across the ISO controlled grid. It is the intent of these guidelines to allow the use of SPSs to maximize the capability of existing transmission facilities while maintaining system reliability and optimizing operability of the ISO controlled grid. Needless to say, with the large number of generator interconnections that are occurring on the ISO controlled grid, the need for these guidelines has become more critical.

It needs to be emphasized that these are guidelines rather than standards. In general, these guidelines are intended to be applied with more flexibility for low exposure outages (e.g., double line outages, bus outages, etc.) than for high exposure outages (e.g., single contingencies). This is to emphasize that best engineering practice and judgement will need to be exercised by system planners and operators in determining when the application of SPS will be acceptable. It is recognized that it is not possible or desirable to have strict standards for the acceptability of the use of SPS in all potential applications.

ISO SPS1 The overall reliability of the system should not be degraded after the combined addition of the SPS.

ISO SPS2 The SPS needs to be highly reliable. Normally, SPS failure will need to be determined to be non-credible. In situations where the design of the SPS requires WECC approval, the WECC Remedial Action Scheme Design Guide will be followed.

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7 / 226 spinning reserves that the ISO has historically been required to carry. The quantities of generation specified in this standard represent the current upper limits for generation tripping. These quantities will be reviewed periodically and revised as needed. In addition, the actual amount of generation that can be tripped is project specific and may depend on specific system performance issues to be addressed. Therefore, the amount of generation that can be tripped for a specific project may be lower than the amounts provided in this guide. The net amount of generation is the gross plant output less the plant’s and other auxiliary load tripped by the same SPS.

ISO SPS4 For SPSs, the following consequences are unacceptable should the SPS fail to operate correctly:

A) Cascading outages beyond the outage of the facility that the SPS is intended to protect: For example, if a SPS were to fail to operate as designed for a single contingency and the transmission line that the SPS was intended to protect were to trip on overload protection, then the subsequent loss of additional facilities due to overloads or system stability would not be an acceptable consequence. B) Voltage instability, transient instability, or small signal instability: While these are rare concerns associated with the addition of new generation, the consequences can be so severe that they are deemed to be unacceptable results following SPS failure.

ISO SPS5 Close coordination of SPS is required to eliminate cascading events. All SPS in a local area (such as SDG&E, Fresno, etc.) and grid-wide need to be evaluated as a whole and studied as such.

ISO SPS6 The SPS must be simple and manageable. As a general guideline:

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8 / 226 addition of a new SPS that deals with the same contingencies covered by an existing SPS. C) Generally, the SPS should only monitor facilities that are connected to the plant or to the first point of interconnection with the grid. Monitoring remote facilities may add substantial complexity to system operation and should be avoided. D) An SPS should not require real-time operator actions to arm or disarm the SPS or change its set points.

ISO SPS7 If the SPS is designed for new generation interconnection, the SPS may not include the involuntary interruption of load. Voluntary interruption of load paid for by the generator is acceptable. The exception is that the new generator can be added to an existing SPS that includes involuntary load tripping. However, the amount of involuntary load tripped by the combined SPS may not be increased as a result of the addition of the generator.

ISO SPS8 Action of the SPS shall limit the post-disturbance loadings and voltages on the system to be within all applicable ratings and shall ultimately bring the system to within the long- term (4 hour or longer) emergency ratings of the transmission equipment. For example, the operation of SPS may result in a transmission line initially being loaded at its one- hour rating. The SPS could then automatically trip or run-back additional generation (or trip load if not already addressed under ISO SPS7 above) to bring the line loading within the line’s four-hour or longer rating. This is intended to minimize real-time operator intervention.

ISO SPS9 The SPS needs to be agreed upon by the ISO and may need to be approved by the WECC Remedial Action Scheme Reliability Task Force.

ISO SPS10 The ISO, in coordination with affected parties, may relax SPS requirements as a temporary “bridge” to system reinforcements. Normally this “bridging” period would be limited to the time it takes to implement a specified alternative solution. An example of a relaxation of SPS requirement would be to allow 8 initiating events rather than limiting the SPS to 6 initiating events until the identified system reinforcements are placed into service.

ISO SPS11 The ISO will consider the expected frequency of operation in its review of SPS proposals.

ISO SPS12 The actual performance of existing and new SPS schemes will be documented by the transmission owners and periodically reviewed by the ISO and other interested parties so that poorly performing schemes may be identified and revised.

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9 / 226 ISO SPS13 All SPS schemes will be documented by the owner of the transmission system where the SPS exists. The generation owner, the transmission owner, and the ISO shall retain copies of this documentation.

ISO SPS14 To ensure that the ISO’s transmission planning process consistently reflects the utilization of SPS in its annual plan, the ISO will maintain documentation of all SPS utilized to meet its reliability obligations under the NERC reliability standards, WECC regional criteria, and ISO planning standards.

ISO SPS15 The transmission owner in whose territory the SPS is installed will, in coordination with affected parties, be responsible for designing, installing, testing, documenting, and maintaining the SPS.

ISO SPS16 Generally, the SPS should trip load and/or resources that have the highest effectiveness factors to the constraints that need mitigation such that the magnitude of load and/or resources to be tripped is minimized. As a matter of principle, voluntary load tripping and other pre-determined mitigations should be implemented before involuntary load tripping is utilized.

ISO SPS17 Telemetry from the SPS (e.g., SPS status, overload status, etc.) to both the Transmission Owner and the ISO is required unless otherwise deemed unnecessary by the ISO. Specific telemetry requirements will be determined by the Transmission Owner and the ISO on a project specific basis.

IV. Combined Line and Generator Unit Outage Standards Supporting Information

Combined Line and Generator Outage Standard - A single transmission circuit outage with one generator already out of service and the system adjusted shall meet the performance requirements of the NERC TPL standards for single contingencies (TPL002).

The ISO Planning Standards require that system performance for an over-lapping outage of a generator unit (G-1) and transmission line (L-1) must meet the same system performance level defined for the NERC standard TPL-002. The ISO recognizes that this planning standard is more stringent than allowed by NERC, but it is considered appropriate for assessing the reliability of the ISO’s controlled grid as it remains consistent with the standard utilized by the PTOs prior to creation of the ISO.

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10 / 226 V. Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard Supporting Information

Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard - A single module of a combined cycle power plant is considered a single (G- 1) contingency and shall meet the performance requirements of the NERC TPL standards for single contingencies (TPL002).

The purpose of this standard is to require that an outage of any turbine element of a combustion turbine be considered as a single outage of the entire plant and therefore must meet the same performance level as the NERC TPL standard TPL-002.

The ISO has determined that, a combined cycle module should be treated as a single contingency. In making this determination, the ISO reviewed the actual operating experience to date with similar (but not identical) combined cycle units currently in operation in California. The ISO's determination is based in large part on the performance history of new combined cycle units and experience to date with these units. The number of combined cycle facility forced outages that have taken place does not support a double contingency categorization for combined cycle module units in general. It should be noted that all of the combined cycle units that are online today are treated as single contingencies.

Immediately after the first few combined cycle modules became operational, the ISO undertook a review of their performance. In defining the appropriate categorization for combined cycle modules, the ISO reviewed the forced outage history for the following three combined cycle facilities in California: Los Medanos Energy Center (Los Medanos), Delta Energy Center (Delta), and Sutter Energy Center (Sutter)1. Los Medanos and Sutter have been in service since the summer of 2001, Delta has only been operational since early summer 2002.

Table 2 below sets forth the facility forced outages for each of these facilities after they went into operation (i.e. forced outages 2that resulted in an output of zero MWs.) The table demonstrates that facility forced outages have significantly exceeded once every 3 to 30 years. Moreover, the ISO considers that the level of facility forced outages is significantly above the once every 3 to 30 years even accounting for the fact that new combined cycle facilities tend to be less reliable during start-up periods and during the initial weeks of operation. For example, four of the forced outages that caused all the

1 Los Medanos and Sutter have two combustion turbines (CT’s) and one steam turbine (ST) each in a 2x1 configuration. Delta has three combustion turbines (CT’s) and one steam turbine (ST) in a 3x1 configuration. All three are owned by the Calpine Corporation. 2 Only forced outages due to failure at the power plant itself are reported, forced outages due to failure on the transmission system/switchyard are excluded. The fact that a facility experienced a forced outage on a particular day is public information. In fact, information on unavailable generating units has been posted daily on the ISO website since January 1, 2001. However, the ISO treats information regarding the cause of an outage as confidential information. M&ID/ID/RT/C. Micsa 11 7/6/2011

11 / 226 three units at Los Medanos to go off-line took place more than nine months after the facility went into operation.

Facility Date # units lost Sutter3 08/17/01 No visibility Sutter 10/08/01 1 CT Sutter 12/29/01 All 3 Sutter 04/15/02 1 CT + ST Sutter 05/28/02 1 CT Sutter 09/06/02 All 3 Los Medanos4 10/04/01 All 3 Los Medanos 06/05/02 All 3 Los Medanos 06/17/02 All 3 Los Medanos 06/23/02 1CT+ST Los Medanos 07/19/02 All 3 Los Medanos 07/23/02 1CT+ST Los Medanos 09/12/02 All 3 Delta5 06/23/02 All 4 Delta 06/29/02 2 CT’s + ST Delta 08/07/02 2 CT’s + ST

Table 2: Forced outages that have resulted in 0 MW output from Sutter, Los Medanos and Delta after they became operational

The ISO realizes that this data is very limited. Nevertheless, the data adequately justifies the current classification of each module of these three power plants as a single contingency.

VI. Background behind Planning for New Transmission versus Involuntary Load Interruption Standard

For practical and economic reasons, all electric transmission systems are planned to allow for some involuntary loss of firm load under certain contingency conditions. For some systems, such a loss of load may require several contingencies to occur while for other systems, loss of load may occur in the event of a specific single contingency. Historically, a wide variation among the PTOs has existed predominantly due to slightly differing planning and design philosophies. This standard is intended to provide a consistent framework upon which involuntary load interruption decisions can be made by the ISO when planning infrastructure needs for the ISO controlled grid.

3 Data for Sutter is recorded from 07/03/01 to 08/10/02 4 Data for Los Medanos is recorded from 08/23/01 to 08/10/02 5 Data for Delta is recorded from 06/17/02 to 08/10/02 M&ID/ID/RT/C. Micsa 12 7/6/2011

12 / 226 The overarching requirement is that implementation of these standards should not result in lower levels of reliability to end-use customers than existed prior to restructuring. As such, the following is required:

1. No single contingency (TPL002 and ISO standard [G-1] [L-1]) may result in loss of more than 250 MW of load. This includes consequential loss of load as well as load that may need to be dropped after the first contingency (during the system adjustment period) in order to protect for the next worst single contingency.

This standard is intended to coordinate ISO planning standards with the WECC requirement that all transmission outages with at least 300 MW or more be directly reported to WECC. It is the ISO’s intent that no single contingency (TPL002 and ISO standard [G-1] [L-1]) should trigger loss of 300 MW or more of load. The 250 MW level is chosen in order to allow for differences between the load forecast and actual real time load that can be higher in some instances than the forecast and to also allow time for transmission projects to become operational since some require 5-6 years of planning and permitting with inherent delays. It is also ISO’s intent to put a cap on the footnote to the NERC TPL-002 that may allow radial and/or non- consequential loss of load for single contingencies.

2. All single substations of 100 MW or more should be served through a looped system with at least two transmission lines “closed in” during normal operation.

This standard is intended to bring consistency between the PTOs’ substation designs. It is not the ISO’s intention to disallow substations with load below 100 MW from having looped connections; however it is ISO’s intention that all substations with peak load above 100 MW must be connected through a looped configuration to the grid.

3. Existing radial loads with available back-tie(s) (drop and automatic or manual pick- up schemes) should have their back-up tie(s) sized at a minimum of 50% of the yearly peak load or to accommodate the load 80% of the hours in a year (based on actual load shape for the area), whichever is more stringent.

This standard is intended to insure that the system is maintained at the level that existed prior to restructuring. It is obvious that as load grows, existing back-ties for radial loads (or remaining feed after a single contingency for looped substations) may not be able to pick up the entire load; therefore the reliability to customers connected to this system may deteriorate over time. It is the ISO’s intention to establish a minimum level of back-up tie capability that needs to be maintained.

4. Upgrades to the system that are not required by the standards in 1, 2 and 3 above may be justified by eliminating or reducing load outage exposure through a benefit to cost ratio (BCR) above 1.0 and/or where there are other extenuating circumstances.

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13 / 226 It is ISO’s intention to allow the build-up of transmission projects that are proven to have a positive benefit to ratepayers by reducing load drop exposure.

Information Required for BCR calculation: For each of the outages that required involuntary interruption of load, the following should be estimated:

o The maximum amount of load that would need to be interrupted. o The duration of the interruption. o The annual energy that would not be served or delivered. o The number of interruptions per year. o The time of occurrence of the interruption (e.g., week day summer afternoon). o The number of customers that would be interrupted. o The composition of the load (i.e., the percent residential, commercial, industrial, and agricultural). o Value of service or performance-based ratemaking assumptions concerning the dollar impact of a load interruption.

The above information will be documented in the ISO Transmission Plan for areas where additional transmission reinforcement is needed or justified through benefit to cost ratio determination.

VII. Interpretations of terms from NERC Reliability Standard and WECC Regional Criteria

Listed below are several ISO interpretations of the terms that are used in the NERC standards that are not already addressed by NERC.

Combined Cycle Power Plant Module: A combined cycle is an assembly of heat engines that work in tandem off the same source of heat, converting it into mechanical energy, which in turn usually drives electrical generators. In a combined cycle power plant (CCPP), or combined cycle gas turbine (CCGT) plant, one or more gas turbine generator(s) generates electricity and heat in the exhaust is used to make steam, which in turn drives a steam turbine to generate additional electricity.

Entity Responsible for the Reliability of the Interconnected System Performance: In the operation of the grid, the ISO has primary responsibility for reliability. In the planning of the grid, reliability is a joint responsibility between the PTO and the ISO subject to appropriate coordination and review with the relevant local, state, regional and federal regulatory authorities.

Entity Required to Develop Load Models: The PTOs, in coordination with the utility distribution companies (UDCs) and others, develop load models.

Entity Required to Develop Load Forecast: The California Energy Commission (CEC) has the main responsibility for providing load forecast. If load forecast is not

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14 / 226 provided by the CEC or is not detailed and/or specific enough for a certain study then the ISO, at its sole discretion, may use load forecasts developed by the PTOs in coordination with the UDCs and others.

Projected Customer Demands: The load level modeled in the studies can significantly impact the facility additions that the studies identify as necessary. For studies that address regional transmission facilities such as the design of major interties, a 1 in 5- year extreme weather load level should be assumed. For studies that are addressing local load serving concerns, the studies should assume a 1 in 10-year extreme weather load level. The more stringent requirement for local areas is necessary because fewer options exist during actual operation to mitigate performance concerns. In addition, due to diversity in load, there is more certainty in a regional load forecast than in the local area load forecast. Having a more stringent standard for local areas will help minimize the potential for interruption of end-use customers.

Planned or Controlled Interruption: Load interruptions can be either automatic or through operator action as long as the specific actions that need to be taken, including the magnitude of load interrupted, are identified and corresponding operating procedures are in place when required.

Time Allowed for Manual Readjustment: This is the amount of time required for the operator to take all actions necessary to prepare the system for the next contingency. This time should be less than 30 minutes.

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15 / 226 141 FERC ¶ 61,209 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman; Philip D. Moeller, John R. Norris, Cheryl A. LaFleur, and Tony T. Clark.

In re California Independent System Docket No. IN13-4-000 Operator Corporation

ORDER APPROVING STIPULATION AND CONSENT AGREEMENT

(Issued December 14, 2012)

1. The Commission approves the attached Stipulation and Consent Agreement (Agreement) between the Office of Enforcement (Enforcement) and the California Independent System Operator Corporation (CAISO). This order is in the public interest because it resolves an investigation by Enforcement regarding CAISO’s compliance with Commission-approved Reliability Standards.1 The investigation examined possible violations of the NERC Reliability Standards by CAISO surrounding a Disturbance2 in the San Diego area of the state of California on March 31-April 1, 2010 (the Disturbance). CAISO admitted to the violations set forth below and agreed to pay a civil penalty of $200,000 to the United States Treasury.

2. CAISO represents that in advance of the finalization of the Agreement it voluntarily has undertaken substantial efforts to address concerns identified during its internal review following the Disturbance and that it has completed the reliability enhancements set forth in the Agreement to meet the concerns identified by Enforcement during this investigation. CAISO will also make semi-annual compliance monitoring reports to Enforcement staff for a period of up to two years.

1 Section 215 of the Federal Power Act provides the Commission the authority to enforce the Reliability Standards. 16 U.S.C. § 824o (2006); see also 18 C.F.R. § 40.2(a) (2011) (requiring compliance with the Reliability Standards).

2 Unless otherwise specified, capitalized terms in this Order have the meanings specified in the NERC Glossary of Terms used in Reliability Standards.

16 / 226 Docket No. IN13-4-000 - 2 -

I. Background

3. As relevant here, CAISO serves as a Balancing Authority and Transmission Operator for Load served by the San Diego Gas & Electric Company (SDG&E). On March 16, 2007, the Commission approved Reliability Standards applicable to those reliability functions3 pursuant to section 215 of the Federal Power Act.4 These standards became mandatory and enforceable within the contiguous United States on June 18, 2007.

4. CAISO also is responsible for Operational Control of the CAISO Controlled Grid, which consists of the system of transmission lines and associated facilities of the Participating Transmission Owners (which include SDG&E).5 These responsibilities include enforcement of the “25 percent Internal Generation Requirement,” which is one of the “Local Reliability Criteria” for the SDG&E area and requires that “Internal Generation [be] maintained at 25 percent of the Native Load at all times” (the 25% Requirement).

5. The 25 percent Requirement is designed “to minimize the risk of further uncontrolled separation, loss of Generation, and or system shutdown in the event of a severe system frequency decline” and serves to “protect[] southern California Load in the event of a system-wide under-frequency event,” making “the southern California system more likely to survive a total separation from the transmission grid external to southern California.”

6. On March 31, 2010, CAISO, in conjunction with SDG&E, established its Day- Ahead Schedule for April 1, 2010. CAISO scheduled the Central La Rosita II Generating Unit (La Rosita II) to provide a substantial portion of the Internal Generation needed to meet the 25 percent Requirement during the first several hours of April 1, 2010.

3 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

4 16 U.S.C. § 824(o) (2006).

5 The terms “Generation,” Generating Unit,” “Operational Control,” “CAISO Controlled Grid,” and “Participating Transmission Owner” have the meanings specified in Appendix A to CAISO’s Fourth Replacement Tariff, which was in effect at the time of the Disturbance.

17 / 226 Docket No. IN13-4-000 - 3 -

7. La Rosita II, however, had suffered an outage on the afternoon of March 31, 2010, and was not available to meet its schedule for April 1. Although CAISO knew that La Rosita II would not provide Internal Generation needed to maintain the 25 percent Requirement on April 1, CAISO failed to plan for replacing that Internal Generation.

8. On March 31, 2010, shortly before midnight, CAISO system operators granted a request from the Otay Mesa Generating Unit (Otay Mesa), which was providing Internal Generation needed to maintain the 25 percent Requirement, to shut down at midnight. In granting this request, CAISO system operators failed to consider whether other Internal Generation online would maintain the 25 percent Requirement in the absence of Otay Mesa and the unplanned outage of La Rosita II.

9. At 23:59 on March 31, 2010, an alarm alerted CAISO’s operators that Internal Generation in the San Diego area had dropped below 25 percent of Native Load. The CAISO operators on shift had not previously encountered a breach of the 25 percent Requirement and had neither been adequately trained nor provided with a documented operating procedure on how to respond to this condition. They mistakenly concluded that they were allowed only 20 minutes in which to increase Internal Generation to meet the 25 percent Requirement; and, if not successful, that they were required to shed Load.

10. On April 1, 2010, at 00:17 and 00:21, the CAISO shift supervisor issued two erroneous directives to SDG&E to shed 290 MW of firm Load. Acting on those directives, SDG&E shed 332 MW of firm Load, depriving approximately 250,000 SDG&E customers of electricity for up to 43 minutes.6

II. Violations

11. To determine whether CAISO complied with the Reliability Standards, Enforcement opened a non-public, preliminary investigation into the events surrounding the Disturbance.7 As detailed in the Agreement, CAISO’s insufficient training, planning, and operating procedures with regard to the 25 percent Requirement gave rise to CAISO’s violation of four requirements set out in two Reliability Standards. CAISO has

6 Because utilities shed Load by distribution block based on predetermined local priorities, SDG&E could not shed precisely the 290 MW of Load specified in CAISO’s directives.

7 On April 6, 2010, prior to the initiation of Enforcement’s investigation, the CAISO issued a press release acknowledging that it “made mistakes, first allowing this situation to occur by not maintaining adequate local generation in San Diego, and then applying operating requirements incorrectly” in shedding Load to meet the 25% Requirement.

18 / 226 Docket No. IN13-4-000 - 4 -

acknowledged responsibility for the mistakes leading to the Load-shedding and admitted to the violations.

12. CAISO violated PER-002-0, Requirement R1, which requires that Transmission Operators and Balancing Authorities “shall be staffed with adequately trained operating personnel,” because its system operators on shift on March 31- April 1, 2010, did not know: (a) that they were not limited to 20 minutes to restore Internal Generation to 25 percent of Load; and (b) that Load should not be shed to maintain or restore the 25 percent Requirement. CAISO violated Requirement R3.1 in that CAISO’s training program failed to define restoration of the 25 percent Requirement as a “training program objective,” even though the 25 percent Requirement was incorporated in CAISO operating procedure G-206 and was, therefore, subject to Requirement R3.1.

13. CAISO violated Reliability Standard TOP-002-2a, Requirement R6, which requires each Balancing Authority and Transmission Operator to “plan to meet unscheduled changes in system configuration and generation dispatch . . . in accordance with NERC, Regional Reliability Organization, subregional, and local reliability requirements.” As we explained in Order No. 693, TOP-002-2a required CAISO “to look ahead to the next hour, day and season, and have operating plans ready to meet any unscheduled changes in system configuration and generation dispatch.”8 The unscheduled outage of La Rosita II presented an occasion for CAISO “to look ahead” and commit resources to be used to maintain the 25 percent Requirement in light of the unscheduled outage and loss of Internal Generation. CAISO violated Reliability Standard TOP-002-2a, Requirement R6 when, instead of having the required plans and resources in place, it relied on intervention “as needed” by its Control Room personnel.

14. CAISO violated Reliability Standard TOP-002-2a, Requirement R1, which required CAISO to have “current plans that are designed to evaluate options and set procedures for reliable operation through a future time period.” CAISO violated TOP-002-2a, Requirement R1 because its operating procedures and current plans failed to include the proscription against shedding Load to maintain or restore the 25 percent Requirement.

15. While in some circumstances, Load-shedding may be necessary to comply with a Reliability Standard, this was not such a circumstance.9

8 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1590, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

9 Cf. Enforcement of Statutes, Orders, Rules and Regulations, 132 FERC ¶ 61,216 at P 78 (2010).

19 / 226 Docket No. IN13-4-000 - 5 -

III. Stipulation and Consent Agreement

16. Under the Agreement, CAISO stipulates to the facts as set forth in the Agreement and admits to the violations of the four requirements of two NERC Reliability Standards, as set forth in this Order. CAISO agrees to pay a civil penalty of $200,000 and to make the semi-annual compliance monitoring reports to Enforcement as set forth in the Agreement.

IV. Determination of the Appropriate Civil Penalty

17. In arriving at the appropriate civil penalty, Commission staff applied the Commission’s Penalty Guidelines and considered the serious nature of the Disturbance and the harm caused by the shedding of firm Load under the circumstances of the Disturbance. Staff also considered CAISO’s admission of the violations; its public acknowledgment, prior to the initiation of Enforcement’s investigation, of responsibility for the failure to maintain the 25 percent Requirement and for the unnecessary Load- shedding that ensued; its cooperation throughout the investigation; and CAISO’s remedial efforts to improve its training with respect to the 25 percent Requirement, to incorporate the 25 percent Requirement into its market software, and to revise its operating procedures by including the proscription against shedding Load to maintain or recover the 25 percent Requirement. The Commission concludes that the civil penalty is consistent with the Revised Policy Statement on Penalty Guidelines.10

18. The Commission concludes that the civil penalty and the compliance monitoring reports specified in the Agreement are fair and equitable and in the public interest.

The Commission orders:

The attached Stipulation and Consent Agreement is hereby approved without modification.

By the Commission.

( S E A L )

Nathaniel J. Davis, Sr., Deputy Secretary.

10 Enforcement of Statutes, Orders, Rules and Regulations, 132 FERC ¶ 61,216 (2010).

20 / 226 UNITED STATES OF AMERICA FEDERAL ENERGY REGULATORY COMMISSION

California Independent System Operator Docket No. IN13-4-000 Corporation

STIPULATION AND CONSENT AGREEMENT

I. Introduction

1. Staff of the Office of Enforcement (Enforcement) of the Federal Energy Regulatory Commission (Commission) and the California Independent System Operator Corporation (CAISO) enter into this Stipulation and Consent Agreement (Agreement) to resolve a non-public investigation by Enforcement and staff of the Office of Electric Reliability of the Commission pursuant to Part 1b of the Commission’s regulations, 18 C.F.R. Part 1b (2012). The investigation examined possible violations of the NERC Reliability Standards by CAISO related to its functions as a Balancing Authority and Transmission Operator and the issuance of two directives to shed firm Load in the San Diego area on April 1, 2010, directives which were unnecessary based on system conditions and thus erroneous. Unless otherwise specified, capitalized terms in this Agreement have the meanings specified in the NERC Glossary of Terms used in Reliability Standards (NERC Glossary).

II. Stipulated Facts

Enforcement and CAISO hereby stipulate to the following:

2. On March 31-April 1, 2010, a Disturbance occurred in the San Diego region of the CAISO Balancing Authority Area when a shift supervisor working in CAISO’s Folsom control room issued two erroneous directives to San Diego Gas and Electric Co. (SDG&E) to shed 290 MW of firm Load. Acting on those directives, SDG&E shed 332 MW of firm Load, depriving approximately 250,000 SDG&E customers of electricity for up to 43 minutes.1

3. On April 6, 2010, the CAISO issued a press release acknowledging that it “made mistakes, first allowing this situation to occur by not maintaining adequate local

1 Because utilities shed Load by distribution block based on predetermined local priorities, SDG&E could not shed precisely the 290 MW of Load specified in CAISO’s directives.

21 / 226 generation in San Diego, and then applying operating requirements incorrectly.” The CAISO stated that it “improperly allowed a San Diego area power plant to shut down. This initial decision led the ISO to operate outside the San Diego import limitation, which requires at least 25 percent of San Diego’s Load to be served by local generation.” The CAISO further stated that its “review has determined that although the ISO acted in good faith and out of an abundance of caution to address the situation and protect the integrity of the entire electric grid, the ISO inappropriately applied an operating requirement that then called for Load shedding to reduce demand.”

4. Following the Disturbance, Enforcement opened a non-public preliminary investigation into the cause of, and the events surrounding, the Disturbance. The investigation disclosed that with respect to one of the “Local Reliability Criteria” for the SDG&E area, which requires “Internal Generation [be] maintained at 25% of the Native Load at all times” (the 25% Requirement), CAISO violated four requirements of two Reliability Standards.

5. As a Balancing Authority, CAISO is responsible for balancing Load, Generation, and Interchange within its Balancing Authority Area; as a Transmission Operator, CAISO is responsible for reliable operation of the transmission facilities it operates. CAISO also is responsible for Operational Control of the CAISO Controlled Grid, which consists of the system of transmission lines and associated facilities of the Participating Transmission Owners (which include SDG&E).2 CAISO system operators at CAISO’s primary control center in Folsom, California and its back-up control center in Alhambra, California, execute CAISO’s reliability functions.

6. The 25% Requirement in the San Diego area stems from a pre-CAISO under- frequency load shedding program developed in concert with, and incorporated into, the “coordinated off-nominal frequency load shedding and restoration plan for the Western Interconnection” (Coordinated Plan), initially adopted in 1997 by the Western System Coordinating Council.3 In May 2000, SDG&E and Southern California Edison reached an agreement in which SDG&E agreed to install additional under-frequency relays to increase SDG&E’s under-frequency Load-shedding capability to 75% and to limit

2 The terms “Generation,” “Generating Unit,” “Operational Control,” “CAISO Controlled Grid,” and “Participating Transmission Owner” have the meanings specified in Appendix A to CAISO’s Fourth Replacement Tariff, which was in effect at the time of the Disturbance.

3 The Western System Coordinating Council is the predecessor to the Western Electricity Coordinating Council (“WECC”).

22 / 226 imports in such a way that at least 25% of the Native Load is served by Generation that will remain connected to the SDG&E system during a separation event. This 75% Load shedding capability exceeded the amount necessary to comply with WECC’s requirement that “control areas, coordinated groups of entities, and other entities serving Load” within the Western Interconnection “establish a program of automatic high-speed Load shedding designed to arrest frequency decay [in order to minimize] the risk of total system collapse in the event of separation….”

7. In July 2002, CAISO incorporated the 25% Requirement into its operating procedure G-206, then titled “Minimum RMR Commitment: San Diego Area,” which remained in effect at the time of the Disturbance. According to CAISO, the enforcement of the 25% Requirement is designed “to minimize the risk of further uncontrolled separation, loss of generation, and or system shutdown in the event of a severe system frequency decline” and serves to “protect[] southern California Load in the event of a system-wide under-frequency event,” making “the southern California system more likely to survive a total separation from the transmission grid external to southern California.”

8. CAISO operates Day-Ahead and Real-Time Markets using market software based on Security-Constrained Economic Dispatch to balance Load and Generation. The 25% Requirement was not a constraint incorporated into CAISO’s market software when the Disturbance occurred. Instead, CAISO and SDG&E created a coordinated daily procedure in order to ensure that enough Generation would be available for the next operating day to maintain the 25% Requirement. Under this procedure, CAISO required SDG&E to provide a daily Transmission Network Analysis (TNA) report, which the CAISO operations engineers considered when evaluating daily commitment needs for the SDG&E area.

9. According to CAISO’s Day-Ahead Schedule for April 1, 2010, the Central La Rosita II Generating Unit (La Rosita II) was scheduled to provide a substantial portion of the Internal Generation needed to meet the 25% Requirement for the first several hours of that day. La Rosita II, however, had suffered an outage on the afternoon of March 31, 2010, and was not available to meet its schedule for April 1.

10. Although CAISO was aware on the afternoon of March 31, 2010, that La Rosita II would not provide the Internal Generation needed to maintain the 25% Requirement on April 1, CAISO failed to adequately plan for replacing the Internal Generation it would not be receiving from La Rosita II on that date, improperly relying instead on “operator intervention,” including calling upon other Generating Units, as needed.

11. On March 31, 2010, San Diego-area Internal Generation fell below 25% because the CAISO mistakenly allowed the Otay Mesa Generating Unit (Otay Mesa), whose

23 / 226 Generation counted toward meeting the 25% Requirement, to shut down for the first four hours of April 1, 2010. The Scheduling Coordinator for Otay Mesa called the CAISO and asked whether Otay Mesa could go offline at midnight, advising that it was scheduled to be shut down but was still receiving dispatch instructions. After confirming that Otay Mesa was scheduled to shut down at midnight, CAISO’s generation dispatchers granted the request at approximately 23:56.4 In doing so, they failed to take into account the level of Internal Generation relative to Load after Otay Mesa went offline and failed to consider whether there was other Internal Generation online sufficient to maintain the 25% Requirement in the absence of Otay Mesa and the unplanned outage of La Rosita II. At 23:59, before Otay Mesa was completely shut down, an alarm appeared on monitors in the Folsom control room alerting the CAISO that Internal Generation in the San Diego area had dropped below 25% of Native Load.

12. The CAISO operators on shift had not previously encountered a breach of the 25% Requirement and had neither been adequately trained nor provided with a documented operating procedure on how to respond to this condition. They immediately sought to have Otay Mesa stay online, but they learned that the shutdown process had proceeded past the point at which it could be reversed. CAISO operators attempted to recover the 25% Requirement by increasing local Generation through additional Generating Units. Although CAISO operators were aware that the level of imported energy in the San Diego area on the morning of April 1, 2010, was within the applicable stability limit, the operators mistakenly concluded that: (a) they were allowed only 20 minutes in which to increase Internal Generation to meet the 25% Requirement; and (b) if not successful, they were required to shed Load. While in some circumstances, Load-shedding may be necessary to comply with a Reliability Standard, this was not such a circumstance.5

III. Violations

13. CAISO’s insufficient training, planning, and operating procedures with regard to the 25% Requirement gave rise to CAISO’s violation of four requirements set out in two

4 All times are Pacific Daylight-Savings Time (PDT) using a 24-hour clock.

5 Cf. Revised Policy Statement on Penalty Guidelines, 132 FERC ¶ 61,216, at P 78 (2010) (“In assessing the penalty for the underlying violation, where shedding Load was necessary in order to comply with a Reliability Standard, we will not consider under section 2A1.1(b)(2) of the Penalty Guidelines the resulting MWh of Load shed to comply with the Reliability Standards. We will however consider the fact that the underlying violation required Load shedding in assessing the risk created by the underlying violation under section 2A1.1(b)(1) of the Penalty Guidelines.”).

24 / 226 Reliability Standards. CAISO has acknowledged responsibility for the mistakes leading to the Load-shedding and admitted to the violations.

A. Reliability Standard PER-002-0, Requirements R1 and R3.1.

14. At all relevant times, Reliability Standard PER-002-0 required the CAISO to “provide [its] personnel with a coordinated training program that will ensure reliable system operations.” Requirement R1 of this standard required that Transmission Operators and Balancing Authorities “shall be staffed with adequately trained operating personnel.” Requirement R3.1 required CAISO to establish “training program objectives” that would ensure its operators had “the knowledge and competencies needed to apply” its operating procedures in “normal, emergency, and restoration conditions.” As CAISO explained, “Load should not be shed to maintain or recover the 25% local generation requirement.” CAISO violated Requirement R1 because its system operators on shift on March 31-April 1, 2010, did not know this proscription against shedding Load to maintain or recover the 25% Requirement. Consequently, CAISO was not “staffed with adequately trained operating personnel” on April 1, 2010, in regard to the 25% Requirement. CAISO violated Requirement R3.1 in that CAISO’s training program failed to define restoration of the 25% Requirement as a “training program objective,” even though the 25% Requirement was incorporated in CAISO operating procedure G- 206 and was, therefore, subject to Requirement R3.1.

B. Reliability Standard TOP-002-2a, Requirement R6

15. At all relevant times, Reliability Standard TOP-002-2a, Requirement R6 required each Balancing Authority and Transmission Operator to “plan to meet unscheduled changes in system configuration and generation dispatch . . . in accordance with NERC, Regional Reliability Organization, subregional, and local reliability requirements.” As the Commission explained in Order No. 693, TOP-002-2a, required the CAISO “to look ahead to the next hour, day and season, and have operating plans ready to meet any unscheduled changes in system configuration and generation dispatch.”6 “The goal . . . is to ensure that resources and operational plans are in place to enable system operators to maintain the Bulk-Power System in a reliable state.”7 The unscheduled outage of La Rosita II presented an occasion for CAISO “to look ahead” and commit resources to be

6 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1590, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

7 Id.

25 / 226 used to maintain the 25% Requirement in light of the unscheduled outage and loss of Internal Generation. CAISO violated Reliability Standard TOP-002-2a, Requirement R6 when, instead of having the required “resources and operational plans ... in place,” it relied on intervention “as needed” by its Control Room personnel.

C. Reliability Standard TOP-002-2a, Requirement R1

16. At all relevant times, Reliability Standard TOP-002-2a, Requirement R1 required “current plans that are designed to evaluate options and set procedures for reliable operation through a future time period.” CAISO violated this requirement because its operating procedures and current plans concerning the 25% Requirement did not include sufficient instructions for recovering the 25% Requirement after a breach. Although CAISO confirmed that “Load should not be shed to maintain or recover the 25% local generation requirement” in any circumstances, its operating procedures did not address this proscription.

IV. Remedies and Sanctions

17. For purposes of settling any and all civil and administrative disputes arising from Enforcement’s investigation, CAISO stipulates to the facts as set forth in the preceding paragraphs and admits to the violations set forth in this Agreement. The CAISO was cooperative throughout the compliance enforcement process.

18. CAISO agrees to undertake the following obligations:

A. Civil Penalty

19. CAISO shall pay a civil penalty in the amount of $200,000 to the United States Treasury within 10 days of the Effective Date of this Agreement.

B. Reliability Enhancement Measures Already Completed

20. CAISO voluntarily has undertaken substantial efforts to address concerns identified during its own internal review following the Disturbance, which address the concerns identified by Enforcement during the course of its investigation. CAISO represents that in advance of the finalization of a settlement it has completed the following reliability enhancements to meet the concerns identified during this investigation:

a. San Diego Procedures Training

In July 2010, CAISO held a training session to review the operating procedures applicable to the San Diego area and how the Reliability

26 / 226 Standards apply to these procedures. CAISO presented a detailed study of the March 31-April 1, 2010 Load-shedding incident for training on the operation of the 25% Requirement and other applicable minimum generation requirements in the San Diego area. These documents identify the training objectives with respect to the 25% Requirement and the applicable NERC, regional and local reliability requirements to the San Diego area, as required by PER-002-0 Requirement R3.1. b. Revised Operating Procedures

CAISO revised its principal operating procedures applicable to the San Diego area and issued a Revised Technical Bulletin concerning the 25% Requirement, so that these procedures now state that Load-shedding may not be used to recover the 25% Requirement. c. Incorporated 25% Requirement in Market Software

CAISO has now included the 25% Requirement as a constraint in its market software, so that unplanned outages as occurred in this instance will be adjusted for in the Security Constrained Economic Dispatch. d. Modified Monitoring of 25% Requirement

CAISO modified its Energy Management System (EMS) and Plant Information (PI) screens to make it easier for operators to ascertain (or calculate) Internal Generation as a percentage of Load and to determine the impact on the 25% Requirement of adding or removing specific internal Generating Units. CAISO included materials on the use of these screens in its revised training materials for the San Diego area. In addition, CAISO modified its alarms so that operators receive warning before Internal Generation has declined below 25%. e. Increased Staffing

In 2011, the CAISO added 24/7 staffing by operating engineers in the control room. The addition of the operating engineers to the control room staff has provided numerous reliability-related benefits, including providing shift personnel with immediate access to critical reliability-related information, such as establishment and validation of system operating limits based upon real-time conditions, running studies prior to authorizing equipment to go out of service, evaluation and validation of contingencies, updated path ratings, troubleshooting EMS or market related issues, and quick follow-up of outage questions.

27 / 226 f. Enhanced Training

The CAISO has created training simulator rooms that replicate in smaller scale the actual control rooms in Alhambra and Folsom for enhanced operator training. Simulator training using these new facilities is now provided quarterly to the operators. The improved training facilities allow for better and more realistic training that replicates the operational behavior of the Bulk Electric System during normal and emergency conditions. C. Compliance Monitoring

21. CAISO shall provide, for one year, starting six months from the Effective Date of this Agreement, semi-annual compliance monitoring reports to Enforcement. The first semi-annual report shall be submitted within ten days after the end of the calendar month which is six months from the Effective Date of this Agreement. Each semi-annual compliance monitoring report will: (1) advise whether CAISO has maintained compliance with the Reliability Standards; (2) describe any new measures taken to ensure compliance with the Reliability Standards in regard to the 25% Requirement; and (3) provide an update of the reliability-related compliance measures instituted and training administered during the preceding semi-annual period.

22. Upon request by Enforcement, CAISO shall provide all documentation supporting its reports. After receipt of the second semi-annual report described in paragraph 21, Enforcement may, at its sole discretion, require CAISO to submit such reports for one additional year.

V. Terms of Consent Agreement

23. The Effective Date of this Agreement shall be the date on which the Commission issues an order approving this Agreement without modification or condition.

24. Unless the Commission issues an order approving the Agreement in its entirety and without modification or condition, the Agreement shall be null and void and of no effect whatsoever, and neither Enforcement nor CAISO shall be bound by any provision or term of the Agreement unless otherwise agreed to in writing by Enforcement and CAISO.

25. The parties shall treat the Agreement as confidential until approved by each party and until the Commission issues an order approving the Agreement without modification or condition. The Agreement shall be made public only after the Commission’s approval without modification or condition.

28 / 226 26. In providing information and documents (CAISO information) to the Commission in connection with the investigation and/or the settlement of the investigation, CAISO invoked the protective provisions of the Commission’s regulations, including 18 C.F.R §§ 1b.9, 1b.20 and 388.112, which provide for the confidential treatment of information submitted to the Commission; and requested that CAISO information be exempt from the mandatory public disclosure requirements of the Freedom of Information Act (5 U.S.C. 552, 552(b)(4)). Other than the public release of the Agreement after the Commission issues an order approving the Agreement in its entirety and without modification or condition, all CAISO information remains subject to the applicable Commission regulations and shall not be disclosed publicly by the Commission other than in accordance such regulations.

27. The Agreement binds CAISO and its agents, successors and assigns. The Agreement does not create or impose any additional or independent obligations on CAISO, any affiliated entity, their respective agents, officers, directors or employees, other than the obligations specifically set forth in this Agreement.

28. In connection with the payment of the civil penalty provided for herein, CAISO agrees that the Commission’s order approving the Agreement without modification or condition shall be a final order assessing a civil penalty under the Federal Power Act, 16 U.S.C. § 791a, et seq., as amended. CAISO further waives rehearing of any Commission order approving the Agreement without modification or condition, and judicial review by any court of any Commission order approving the Agreement without modification or condition.

29. Commission approval of this Agreement without modification or condition shall fully, irrevocably, and unconditionally release CAISO, its agents, officers, directors, and employees, both past and present, and any successor in interest to CAISO from liability for, and forever bar the Commission from bringing against CAISO, its agents, officers, directors, and employees, both past and present, and any successor in interest to CAISO, any and all direct and/or indirect administrative, civil, or other claims (whether or not known) arising out of, related to, or connected with the Disturbance or the investigation. In further consideration for this release, CAISO represents that it is not aware of any material facts concerning the Disturbance that were not disclosed to Enforcement during the investigation and which might reasonably be considered to be a violation of any Reliability Standard. Upon the Effective Date of this Agreement, Enforcement’s investigation of CAISO shall terminate.

30. Failure to make a timely payment or to comply with any other provision of this Agreement shall be deemed a violation of a final order of the Commission issued pursuant to the Federal Power Act and may subject CAISO to additional action under the enforcement and penalty provisions of the Federal Power Act.

29 / 226 31. If CAISO does not make the payment above at or before the time agreed to by the parties, interest will begin to accrue and be payable to the United States Treasury, pursuant to the Commission’s regulations at 18 C.F.R. § 35.19(a)(2)(iii) (2012), from the date that payment is due.

32. The signatories to the Agreement agree that they enter into the Agreement voluntarily and that, other than the recitations set forth herein, no tender, offer, or promise of any kind by any member, employee, officer, director, agent, or representative of Enforcement or CAISO has been made to induce the signatories or any other party to enter into the Agreement.

33. Each of the undersigned warrants that he or she is an authorized representative of the entity designated, is authorized to bind such entity, and accepts the Agreement on the entity’s behalf.

34. This Agreement is executed by each party in duplicate, each of which, so executed, shall be treated as an original for all purposes.

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California ISO Planning Standards

Effective November 2, 2017

31 / 226 Table of Contents

I. Introduction

II. ISO Planning Standards 1. Applicability of NERC Reliability Standards to Low Voltage Facilities under ISO Operational Control 2. Voltage Standard 3. Specific Nuclear Unit Standards 4. Loss of Combined Cycle Power Plant Module as a Single Generator Outage 5. Planning for New Transmission versus Involuntary Load Interruption Standard 6. Planning for High Density Urban Load Centers Standard 7. San Francisco-Peninsula Extreme Event Reliability Standard

III. ISO Planning Guidelines 1. Special Protection Systems

IV. Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard Supporting Information

V. Background behind Planning for New Transmission versus Involuntary Load Interruption Standard

VI. Background behind Planning for High Density Urban Load Area Standard

VII. Interpretations of Terms from the NERC Reliability Standards and WECC Regional Criteria

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I. Introduction

NERC Reliability Standards and WECC Regional Criteria:

The following links provide the minimum standards that ISO needs to follow in its planning process unless NERC or WECC formally grants an exemption or deference to the ISO. They are the NERC Transmission Planning (TPL) standards, other applicable NERC standards (i.e., NUC-001 Nuclear Plant Interface Requirements (NPIRs) for Diablo Canyon Power Plant), and the WECC Regional Criteria: http://www.nerc.com/pa/stand/Pages/ReliabilityStandardsUnitedStates.aspx?jurisdiction =United States https://www.wecc.biz/Standards/Pages/Default.aspx

M&ID/ID 3 November 2, 2017

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II. ISO Planning Standards

The ISO Planning Standards are:

1. Applicability of NERC Reliability Standards to Low Voltage Facilities under ISO Operational Control

The ISO will apply NERC Transmission Planning (TPL) standards, the NUC-001 Nuclear Plant Interface Requirements (NPIRs) for Diablo Canyon Power Plant, and the approved WECC Regional Criteria to facilities with voltages levels less than 100 kV or otherwise not covered under the NERC Bulk Electric System definition that have been turned over to the ISO operational control.

2. Voltage Standard

Voltage and system performance must meet WECC Regional Criteria TPL-001- WECC-CRT-3 https://www.wecc.biz/Reliability/TPL-001-WECC-CRT-3.1.pdf.

In accordance with Requirements WR2 and WR3 of WECC Regional Criteria TPL- 001-WECC-CRT-3 the following standards and limits are to be used within the ISO controlled grid.

Table 1: ISO steady state voltage standard.

Normal Conditions (P0) Contingency Conditions (P1-P7) Voltage Deviation Voltage level Vmax (pu) Vmin (pu) Vmax (pu) Vmin (pu) P1&P3 ≤ 200 kV 1.05 0.95 1.10 0.90 ≤8% ≥ 200 kV 1.05 0.95 1.10 0.90 ≤8% ≥ 500 kV 1.05 1.00 1.10 0.90 ≤8%

The voltage deviation applies only to load and generating buses within the ISO controlled grid (including generator auxiliary load). The maximum total voltage deviation for standard TPL-001-4 category P3 is ≤8% measured from the voltage that exists after the initial condition (loss of generator unit followed by system adjustments) and therefore takes into consideration only voltage deviation due to the second event.

All buses within the ISO controlled grid that cannot meet the requirements specified in Table 1 will require further investigation. Exceptions to this voltage standard may be granted by the ISO and will be documented through stakeholder process. The ISO will make public all exceptions through its website.

M&ID/ID 4 November 2, 2017

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Exceptions and clarifications by PTO area:

Table 2: System Voltage Limits in SCE Area

Steady State Steady State Nominal Pre-Contingency Post-Contingency Facility Voltage High Low High Low (kV/p.u.) (kV/p.u.) (kV/p.u.) (kV/p.u.) All buses 525 kV 540/1.029 520/0.990 550/1.0482 498.8/0.950 Alamitos, Arcogen, Huntington 230 kV 230/1.0001 220/0.957 230/1.0002 207/0.900 Beach, Mandalay, Redondo Bailey, Chevmain, Cima, Colorado River, Cool Water, Eagle Mt., Eagle Rock, El Casco, Gene, Harborgen, Highwind,

Iron Mt., 230 kV 241.5/1.050 218.5/0.95 245/1.0652 207/0.900 Inyo,

Ivanpah, Johanna, Lewis, Primm, Rancho Vista, Red Bluff, Sandlot, Santiago, Serrano, Whirlwind, Windhub All other buses 230 kV 241.5/1.050 218.5/0.95 242/1.0522 207/0.900 Eagle Mtn, 161 kV 169/1.0502 152.95/0.950 169/1.0502 144.9/0.900 Blythe Cool Water, Inyokern, 115 kV 120.75/1.050 109.25/0.950 121/1.0522 103.5/0.900 Kramer, Victor Control, 115 kV 120.75/1.05 117/1.026 121/1.0522 114.5/0.996 Inyo All other buses 115 kV 120.75/1.050 109.25/0.950 123/1.0702 103.5/0.900 All buses 66 kV 69.3/1.050 62.7/0.950 72.5/1.0902 59.4/0.900

1 Due to equipment (circuit breaker) voltage limit.

M&ID/ID 5 November 2, 2017

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Table 3: System Voltage Limits in PG&E Area

Steady State Steady State Nominal Pre-Contingency Post-Contingency Facility Voltage High Low High Low (kV/p.u.) (kV/p.u.) (kV/p.u.) (kV/p.u.) DCPP bus 500 kV 545/1.090 512/1.024 550/1.100 512/1.024 All other buses 500 kV 550/1.100 518/1.036 550/1.100 473/0.946 DCPP bus 230 kV 242/1.052 218/0.948 242/1.052 207/0.900 All other buses 230 kV 242/1.052 219/0.952 242/1.052 207/0.900 All buses 115 kV 121/1.0522 109/0.948 121/1.0521 104/0.904 All buses 70 kV 72.5/1.036 66.5/0.950 72.5/1.036 63.0/0.900 All buses 60 kV 63.0/1.050 57.0/0.950 66.0/1.100 54.0/0.900

Maximum voltage deviation: DCPP 230 kV bus at 11 kV or 4.78%.

Table 4: System Voltage Limits in SDG&E Area

Steady State Steady State Nominal Pre-Contingency Post-Contingency Facility Voltage High Limit Low Limit High Limit Low Limit (kV) (kV) (kV) (kV) All buses 525 kV 550/1.048 498.75/0.950 550/1.048 472.5/0.900 All buses 230 kV 241.5/1.050 218.5/0.950 241.5/1.050 207/0.900 All buses 138 kV 144.9/1.050 131.1/0.950 144.9/1.050 124.2/0.900 All buses 69 kV 72.45/1.050 65.55/0.950 72.45/1.050 62.1/0.900

Table 5: System Voltage Limits in VEA Area

Steady State Steady State Pre-Contingency Post-Contingency System Facility High Low High Low (kV/p.u.) (kV/p.u.) (kV/p.u.) (kV/p.u.) All buses 230 kV 248.4/1.080 218.5/0.950 253/1.100 207/0.900 All buses 138 kV 149.0/1.080 131.1/0.950 151.8/1.100 124.2/0.900

Table 6: System Voltage Limits for Trans Bay Cable

Steady State Steady State Pre-Contingency Post-Contingency System Facility High Limit Low Limit High Limit Low Limit (kV/p.u.) (kV/p.u.) (kV/p.u.) (kV/p.u.) All buses 230 kV 241.5/1.050 218.5/0.950 253/1.100 207/0.900 All buses 115 kV 120.75/1.050 109.25/0.950 126.5/1.100 103.5/0.900

2 PG&E Utility Standard TD1036S allows 115 kV voltages to operate as high as 126 kV until capital projects can be placed into service to achieve a desired operating limit of 121 kV.

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3. Specific Nuclear Unit Standards

The criteria pertaining to the Diablo Canyon Power Plant (DCPP), as specified in the NUC-001 Nuclear Plant Interface Requirements (NPIRs) for DCPP, and Appendix E of the Transmission Control Agreement located on the ISO web site at: http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=3972DF1A-2A18- 4104-825C-E24350BA838F

4. Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard

A single module of a combined cycle power plant is considered a single contingency (G-1) and shall meet the performance requirements of the NERC TPL- 001-4 standard for single contingencies (P1). Supporting information is located in Section IV of this document. Furthermore any reference to the loss of a “generator unit” in the NERC multiple contingency standards (P3-P5) shall be similar to the loss of a “single module of a combined cycle power plant”.

5. Planning for New Transmission versus Involuntary Load Interruption Standard

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infrastructure improvements. It does not address all circumstances under which load dropping is permitted under NERC and WECC planning standards.

1. No single contingency (TPL-001-4 P1) should result in loss of more than 250 MW of load. 2. All single substations of 100 MW or more should be served through a looped system with at least two transmission lines “closed in” during normal operation. 3. Existing radial loads with available back-tie(s) (drop and automatic or manual pick-up schemes) should have their back-up tie(s) sized at a minimum of 50% of the yearly peak load or to accommodate the load 80% of the hours in a year (based on actual load shape for the area), whichever is more constraining. 4. Upgrades to the system that are not required by the standards in 1, 2 and 3 above may be justified by eliminating or reducing load outage exposure, through a benefit to cost ratio (BCR) above 1.0 and/or where there are other extenuating circumstances.

6. Planning for High Density Urban Load Area Standard

6.1 Local Area Planning

A local area is characterized by relatively small geographical size, with limited transmission import capability and most often with scarce resources that usually can be procured at somewhat higher prices than system resources.3 The local areas are planned to meet the minimum performance established in mandatory standards or other historically established requirements, but tend to have little additional flexibility beyond the planned-for requirements taking into account both local generation and transmission capacity. Increased reliance on load shedding to meet these needs would run counter to historical and current practices, resulting in general deterioration of service levels.

For local area long-term planning, the ISO does not allow non-consequential load dropping in high density urban load areas in lieu of expanding transmission or local resource capability to mitigate NERC TPL-001-4 standard P1-P7 contingencies and impacts on the 115 kV or higher voltage systems.

 In the near-term planning, where allowed by NERC standards, load dropping, including high density urban load, may be used to bridge the gap between real-time operations and the time when system reinforcements are built.  In considering if load shedding, where allowed by NERC standards, is a viable mitigation in either the near-term, or the long-term for local areas

3 A “local area” for purposes of this Planning Standard is not necessarily the same as a Local Capacity Area as defined in the CAISO Tariff.

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that would not call upon high density urban load, case-by-case assessments need to be considered. Assessments should take in consideration, but not limited to, risk assessment of the outage(s) that would activate the SPS including common right of way, common structures, history of fires, history of lightning, common substations, restoration time, coordination among parties required to operate pertinent part of the transmission system, number of resources in the area, number of customers impacted by the outage, outage history for resources in the area, retirement impacts, and outage data for the local area due to unrelated events.

6.2 System Wide Planning

System planning is characterized by much broader geographical size, with greater transmission import capability and most often with plentiful resources that usually can be procured at somewhat lower prices than local area resources. Due to this fact more resources are available and are easier to find, procure and dispatch. Provided it is allowed under NERC reliability standards, the ISO will allow non- consequential load dropping system-wide SPS schemes that include some non- consequential load dropping to mitigate NERC TPL-001-4 standard P1-P7 contingencies and impacts on the 115 kV or higher voltage systems.

7. Extreme Event Reliability Standard

The requirements of NERC TPL-001-4 require Extreme Event contingencies to be assessed; however the standard does not require mitigation plans to be developed for these Extreme Events. The ISO has identified in Section 7.1 below that the San Francisco Peninsula area has unique characteristics requiring consideration of corrective action plans to mitigate the risk of extreme events. Other areas of the system may also be considered on a case-by-case basis as a part of the transmission planning assessments.

7.1 San Francisco-Peninsula - Extreme Event Reliability Standard

The ISO has determined through its Extreme Event assessments, conducted as a part of the annual transmission planning process, that there are unique characteristics of the San Francisco Peninsula area requiring consideration for mitigation as follows.

 high density urban load area,  geographic and system configuration,  potential risks of outages including seismic, third party action and collocating facilities; and  challenging restoration times.

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The unique characteristics of the San Francisco Peninsula form a credible basis for considering for approval corrective action plans to mitigate the risk of outages that are beyond the application of mitigation of extreme events in the reliability standards to the rest of the ISO controlled grid. The ISO will consider the overall impact of the mitigation on the identified risk and the associated benefits that the mitigation provides to the San Francisco Peninsula area.

III. ISO Planning Guidelines

The ISO Planning Guidelines include the following:

1. Special Protection Systems

The primary reasons why SPS might be selected over building new transmission facilities are that SPS can normally be implemented much more quickly and at a much lower cost than constructing new infrastructure. In addition, SPS can increase the utilization of the existing transmission facilities, make better use of scarce transmission resources and maintain system reliability. Due to these advantages, SPS is a commonly considered alternative to building new infrastructure in an effort to keep costs down when integrating new generation into the grid and/or addressing reliability concerns under multiple contingency conditions. While SPSs have substantial advantages, they have disadvantages as well. With the increased transmission system utilization that comes with application of SPS, there can be increased exposure to not meeting system performance criteria if the SPS fails or inadvertently operates. Transmission outages can become more difficult to schedule due to increased flows across a larger portion of the year; and/or the system can become more difficult to operate because of the independent nature of the SPS. If there are a large number of SPSs, it may become difficult to assess the interdependency of these various schemes on system reliability. These reliability concerns necessarily dictate that guidelines be established to ensure that performance of all SPSs are consistent across the ISO controlled grid. It is the intent of these guidelines to allow the use of SPSs to maximize the capability of existing transmission facilities while maintaining system reliability and optimizing operability of

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the ISO controlled grid. Needless to say, with the large number of generator interconnections that are occurring on the ISO controlled grid, the need for these guidelines has become more critical.

It needs to be emphasized that these are guidelines rather than standards and should be used in the development of any new SPS. In general, these guidelines are intended to be applied with more flexibility for low exposure outages (e.g., double line outages, bus outages, etc.) than for high exposure outages (e.g., single contingencies). This is to emphasize that best engineering practice and judgment will need to be exercised by system planners and operators in determining when the application of SPS will be acceptable. It is recognized that it is not possible or desirable to have strict standards for the acceptability of the use of SPS in all potential applications.

ISO SPS1 The overall reliability of the system should not be degraded after the combined addition of the SPS.

ISO SPS3 The total net amount of generation tripped by a SPS for a single contingency cannot exceed the ISO’s largest single generation contingency (currently one Diablo Canyon unit at 1150 MW). The total net amount of generation tripped by a SPS for a double contingency cannot exceed 1400 MW. This amount is related to the minimum amount of spinning reserves that the ISO has historically been required to carry. The quantities of generation specified in this standard represent the current upper limits for generation tripping. These quantities will be reviewed periodically and revised as needed. In addition, the actual amount of generation that can be tripped is project specific and may depend on specific system performance issues to be addressed. Therefore, the amount of generation that can be tripped for a specific project may be lower than the amounts provided in this guide. The net amount of generation is the gross plant output less the plant’s and other auxiliary load tripped by the same SPS.

ISO SPS4 For SPSs, the following consequences are unacceptable should the SPS fail to operate correctly:

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B) Voltage instability, transient instability, or small signal instability: While these are rare concerns associated with the addition of new generation, the consequences can be so severe that they are deemed to be unacceptable results following SPS failure.

ISO SPS5 Close coordination of SPS is required to eliminate cascading events. All SPS in a local area (such as SDG&E, Fresno, etc.) and grid-wide need to be evaluated as a whole and studied as such.

ISO SPS6 The SPS must be simple and manageable. As a general guideline:

A) There should be no more than 6 local contingencies (single or credible double contingencies) that would trigger the operation of a SPS. B) The SPS should not be monitoring more than 4 system elements or variables. A variable can be a combination of related elements, such as a path flow, if it is used as a single variable in the logic equation. Exceptions include: i. The number of elements or variables being monitored may be increased if it results in the elimination of unnecessary actions, for example: generation tripping, line sectionalizing or load shedding. ii. If the new SPS is part of an existing SPS that is triggered by more than 4 local contingencies or that monitors more than 4 system elements or variables, then the new generation cannot materially increase the complexity of the existing SPS scheme. However, additions to an existing SPS using a modular design should be considered as preferable to the addition of a new SPS that deals with the same contingencies covered by an existing SPS. C) Generally, the SPS should only monitor facilities that are connected to the plant or to the first point of interconnection with the grid. Monitoring remote facilities may add substantial complexity to system operation and should be avoided. D) An SPS should not require real-time operator actions to arm or disarm the SPS or change its set points.

ISO SPS8 Action of the SPS shall limit the post-disturbance loadings and voltages on the system to be within all applicable ratings and shall ultimately bring the system to within the long-

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term (4 hour or longer) emergency ratings of the transmission equipment. For example, the operation of SPS may result in a transmission line initially being loaded at its one- hour rating. The SPS could then automatically trip or run-back additional generation (or trip load if not already addressed under ISO SPS7 above) to bring the line loading within the line’s four-hour or longer rating. This is intended to minimize real-time operator intervention.

ISO SPS9 The SPS needs to be agreed upon by the ISO and may need to be approved by the WECC Remedial Action Scheme Reliability Task Force.

ISO SPS11 The ISO will consider the expected frequency of operation in its review of SPS proposals.

ISO SPS13 All SPS schemes will be documented by the owner of the transmission system where the SPS exists. The generation owner, the transmission owner, and the ISO shall retain copies of this documentation.

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IV. Loss of Combined Cycle Power Plant Module as a Single Generator Outage Standard Supporting Information

Immediately after the first few combined cycle modules became operational, the ISO undertook a review of their performance. In defining the appropriate categorization for combined cycle modules, the ISO reviewed the forced outage history for the following three combined cycle facilities in California: Los Medanos Energy Center (Los Medanos), Delta Energy Center (Delta), and Sutter Energy Center (Sutter)4. Los Medanos and Sutter have been in service since the summer of 2001, Delta has only been operational since early summer 2002.

4 Los Medanos and Sutter have two combustion turbines (CT’s) and one steam turbine (ST) each in a 2x1 configuration. Delta has three combustion turbines (CT’s) and one steam turbine (ST) in a 3x1 configuration. All three are owned by the Calpine Corporation.

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Table 2 below sets forth the facility forced outages for each of these facilities after they went into operation (i.e. forced outages 5that resulted in an output of zero MWs.) The table demonstrates that facility forced outages have significantly exceeded once every 3 to 30 years. Moreover, the ISO considers that the level of facility forced outages is significantly above the once every 3 to 30 years even accounting for the fact that new combined cycle facilities tend to be less reliable during start-up periods and during the initial weeks of operation. For example, four of the forced outages that caused all the three units at Los Medanos to go off-line took place more than nine months after the facility went into operation.

Facility Date # units lost Sutter6 08/17/01 No visibility Sutter 10/08/01 1 CT Sutter 12/29/01 All 3 Sutter 04/15/02 1 CT + ST Sutter 05/28/02 1 CT Sutter 09/06/02 All 3 Los Medanos7 10/04/01 All 3 Los Medanos 06/05/02 All 3 Los Medanos 06/17/02 All 3 Los Medanos 06/23/02 1CT+ST Los Medanos 07/19/02 All 3 Los Medanos 07/23/02 1CT+ST Los Medanos 09/12/02 All 3 Delta8 06/23/02 All 4 Delta 06/29/02 2 CT’s + ST Delta 08/07/02 2 CT’s + ST

Table 2: Forced outages that have resulted in 0 MW output from Sutter, Los Medanos and Delta after they became operational

The ISO realizes that this data is very limited. Nevertheless, the data adequately justifies the current classification of each module of these three power plants as a single contingency.

5 Only forced outages due to failure at the power plant itself are reported, forced outages due to failure on the transmission system/switchyard are excluded. The fact that a facility experienced a forced outage on a particular day is public information. In fact, information on unavailable generating units has been posted daily on the ISO website since January 1, 2001. However, the ISO treats information regarding the cause of an outage as confidential information. 6 Data for Sutter is recorded from 07/03/01 to 08/10/02 7 Data for Los Medanos is recorded from 08/23/01 to 08/10/02 8 Data for Delta is recorded from 06/17/02 to 08/10/02

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V. Background behind Planning for New Transmission versus Involuntary Load Interruption Standard

The overarching requirement is that implementation of these standards should not result in lower levels of reliability to end-use customers than existed prior to restructuring. As such, the following is required:

1. No single contingency (TPL-001-4 P1) may result in loss of more than 250 MW of load.

This standard is intended to coordinate ISO planning standards with the WECC requirement that all transmission outages with at least 300 MW or more be directly reported to WECC. It is the ISO’s intent that no single contingency (TPL-001-4 P1) should trigger loss of 300 MW or more of load. The 250 MW level is chosen in order to allow for differences between the load forecast and actual real time load that can be higher in some instances than the forecast and to also allow time for transmission projects to become operational since some require 5-6 years of planning and permitting with inherent delays. It is also ISO’s intent to put a cap on the radial and/or consequential loss of load allowed under NERC standard TPL- 001-4 single contingencies (P1).

2. All single substations of 100 MW or more should be served through a looped system with at least two transmission lines “closed in” during normal operation.

This standard is intended to insure that the system is maintained at the level that existed prior to restructuring. It is obvious that as load grows, existing back-ties for

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radial loads (or remaining feed after a single contingency for looped substations) may not be able to pick up the entire load; therefore the reliability to customers connected to this system may deteriorate over time. It is the ISO’s intention to establish a minimum level of back-up tie capability that needs to be maintained.

It is ISO’s intention to allow the build-up of transmission projects that are proven to have a positive benefit to ratepayers by reducing load drop exposure.

Information Required for BCR calculation: For each of the outages that required involuntary interruption of load, the following should be estimated:

The above information will be documented in the ISO Transmission Plan for areas where additional transmission reinforcement is needed or justified through benefit to cost ratio determination.

VI. Background behind Planning for High Density Urban Load Area Standard for Local Areas

A local area is characterized by relatively small geographical size, with limited transmission import capability and most often with scarce resources that usually can be procured at somewhat higher prices than system resources. These areas are planned to meet the minimum performance established in mandatory standards or other historically established requirements, but tend to have little additional flexibility beyond the planned-for requirements taking into account both local resource and transmission capacity. The need for system reinforcement in a number of local areas is expected to climb due to projected resource retirements, with single and double contingency conditions playing a material role in driving the need for reinforcement. Relying on load shedding on a broad basis to meet these emerging needs would run counter to historical and current practices, resulting in general deterioration of service levels. One

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of the fundamental ISO Tariff requirements is to maintain service reliability at pre-ISO levels, and it drives the need to codify the circumstances in which load shedding is not an acceptable long-term solution:

1. For local area long-term planning, the ISO does not allow non-consequential load dropping in high density urban load areas in lieu of expanding transmission or local resource capability to mitigate NERC TPL-001-4 standard P1-P7 contingencies and impacts on the 115 kV or higher voltage systems.

This standard is intended to continue avoiding the need to drop load in high density urban load areas due to, among other reasons, high impacts to the community from hospitals and elevators to traffic lights and potential crime.

The following is a link to the 2010 Census Urban Area Reference Maps:

http://www.census.gov/geo/maps-data/maps/2010ua.html

This site has diagrams of the following urbanized areas which contain over one million persons.

Los Angeles--Long Beach--Anaheim, CA San Francisco--Oakland, CA San Diego, CA Riverside--San Bernardino, CA San Jose, CA

2. In the near-term planning, where allowed by NERC standards, load dropping, including high density urban load, may be used to bridge the gap between real- time operations and the time when system reinforcements are built.

This standard is intended to insure that a reliable transition exists between the time when problems could arise until long-term transmission upgrades are placed in service.

3. In considering if load shedding, where allowed by NERC standards, is a viable mitigation in either the near-term, or the long-term for local areas that would not call upon high density urban load, case-by-case assessments need to be considered. Assessments should take in consideration, but not limited to, risk assessment of the outage(s) that would activate the SPS including common right of way, common structures, history of fires, history of lightning, common substations, restoration time, coordination among parties required to operate pertinent part of the transmission system, number of resources in the area, outage history for resources in the area, retirement impacts, and outage data for the local area due to unrelated events.

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It is ISO’s intention to thoroughly evaluate the risk of outages and their consequences any time a load shedding SPS is proposed regardless of population density.

VII. Interpretations of terms from NERC Reliability Standard and WECC Regional Criteria

Listed below are several ISO interpretations of the terms that are used in the NERC standards that are not already addressed by NERC.

Entity Required to Develop Load Models: The PTOs, in coordination with the utility distribution companies (UDCs) and others, develop load models.

Entity Required to Develop Load Forecast: The California Energy Commission (CEC) has the main responsibility for providing load forecast. If load forecast is not provided by the CEC or is not detailed and/or specific enough for a certain study then the ISO, at its sole discretion, may use load forecasts developed by the PTOs in coordination with the UDCs and others.

Footnote 12 of TPL-001-4 Interpretation and Applicable Timeline9: The shedding of Non-Consequential load following P1, P2-1 and P3 contingencies on the Bulk Electric System of the ISO Controlled Grid is not considered appropriate in meeting the performance requirements. In the near-term planning horizon the requirements of Footnote 12 may be applied until the long-term mitigation plans are in-service. In the near-term transmission planning horizon, the non-consequential load loss will be limited to 75 MW and has to meet the conditions specified in Attachment 1 of TPL-001-4.

9Implementation and applicable timeline will remain the same as the “Effective Date:”(s) described in the NERC TPL-001-4 standard.

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High Density Urban Load Area: Is an Urbanized Area, as defined by the US Census Bureau10 with a population over one million persons.

10 Urbanized Area (UA): A statistical geographic entity consisting of a densely settled core created from census tracts or blocks and contiguous qualifying territory that together have a minimum population of at least 50,000 persons.

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50 / 226 2019 & 23 Final LCR Study Results Summary of Findings

Catalin Micsa Senior Advisor Regional Transmission Engineer

Stakeholder Call May 1, 2018

ISO Public

51 / 226 LCR Areas within CAISO

Big Creek Ventura

Valley Electric

ISO Public Slide 2

52 / 226 Input Assumptions, Methodology and Criteria See October 31, 2017 stakeholder teleconference - for study assumptions, methodology and criteria. The latest information along with the 2019 LCR Manual can be found at: http://www.caiso.com/informed/Pages/StakeholderProcesses/LocalCapacityRe quirementsProcess.aspx . Transmission system configuration – all-projects with EDRO up to June 1, 2019 Generation – all-generation with COD up to June 1, 2019 Load Forecast – 1 in 10 local area peak (based on latest CEC forecast) Criteria – see report for details Methodology 1. Maximize Imports Capability into the local area 2. Maintain path flows 3. Maintain deliverability for deliverable units 4. Load pocket – fix definition

5. Performance levels B & C (if equal category B is most stringent) Slide 3 ISO Public

53 / 226 Major Changes from last year studies

1. New 2018 NQC data. 2. LCR results herein use CEC 8760 load forecast. 3. Total 2019 LCR needs have increased by 37 MW or ~ 0.0%. 4. 2019 LCR needs decrease in: Humboldt due to load forecast decrease, Bay Area due to new transmission projects, Fresno due to decrease in load forecast and due to new transmission projects, San Diego due to downward trend for load combined with an increase due loss of NQC at the most effective location in mitigating the most limiting contingency. 5. 2019 LCR needs increase in: North Coast/North Bay, Stockton, Big Creek/Ventura, LA Basin due to load forecast increase and Sierra due to load and resource distribution, Kern due to change in limiting line section.

ISO Public Slide 4

54 / 226 2019 Final LCR Needs

2019 LCR Need Based on Category B 2019 LCR Need Based on Category Qualifying Capacity C with operating procedure

QF/ Existing Existing Market Total Deficienc Total Deficienc Total Local Area Name Muni Capacity Capacity (MW) (MW) y (MW) y (MW) (MW) Needed Needed**

Humboldt 0 202 202 116 0 116 165 0 165

North Coast/ North Bay 119 771 890 689 0 689 689 0 689

Sierra 1146 1004 2150 1362 0 1362 1964 283* 2247

Stockton 144 489 633 405 5* 410 427 350* 777

Greater Bay 628 6448 7076 3670 0 3670 4461 0 4461

Greater Fresno 340 3177 3517 1406 0 1406 1670 1* 1671

Kern 13 462 475 148 6* 154 472 6* 478

LA Basin 1445 9421 10866 7968 0 7968 8116 0 8116 Big Creek/Ventura 424 4649 5073 2333 0 2333 2614 0 2614

San Diego/ Imperial Valley 106 4285 4391 4026 0 4026 4026 0 4026

Total 4365 30908 35273 22123 11 22134 24604 640 25244

ISO Public Slide 5

55 / 226 Major Changes from last year studies

1. Total 2023 LCR needs have decreased by about 414 MW or ~1.7%. 2. 2023 LCR needs decrease in: Humboldt due to decrease in load forecast and Bay Area, Sierra and Stockton due to new transmission projects, Fresno and San Diego/Imperial Valley due to load forecast decrease and new transmission projects. 3. 2023 LCR needs increase in: North Coast/North Bay, Big Creek /Ventura and LA Basin due to load forecast increase, Kern due to new sub-area needs.

Role and Purpose of sub-area LCR needs:  Provide detail local procurement information  Need to be satisfied in order to minimize ISO back-stop  Sum of the parts may not equal the overall need

ISO Public Slide 6

56 / 226 2023 Final LCR Needs

2023 LCR Need Based on Category B 2023 LCR Need Based on Category C Qualifying Capacity with operating procedure

QF/ Existing Existing Market Total Total Total Local Area Name Muni Capacity Deficiency Capacity Deficiency (MW) (MW) (MW) (MW) (MW) Needed Needed**

Humboldt 0 202 202 111 0 111 169 0 169

North Coast/North Bay 119 771 890 553 0 553 553 0 553

Sierra 1146 1004 2150 1268 0 1268 1924 0 1924

Stockton 144 540 684 225 20* 245 333 106* 439

Greater Bay 627 6427 7054 3676 0 3676 4752 0 4752

Greater Fresno 340 3177 3517 1688 0 1688 1688 0 1688

Kern 13 462 475 152 6* 158 174 8* 182

LA Basin 1443 6868 8311 6793 0 6793 6793 0 6793

Big Creek/Ventura 424 3082 3506 2212 0 2212 2690 102* 2792

San Diego/Imperial Valley 106 4414 4520 4132 0 4132 4132 0 4132

Total 4362 26947 31309 20810 26 20836 23208 216 23424

ISO Public Slide 7

57 / 226 Near-Term LCR Study Schedule

CPUC and the ISO have determined overall timeline – Criteria, methodology and assumptions meeting Oct. 31, 2017 – Submit comments by November 14, 2017 – Posting of comments with ISO response by the December 12, 2017 – Base case development started in December 2017 – Receive base cases from PTOs January 2018 – Publish base cases January 19, 2018 – comments by Feb. 2nd – Receive and incorporate CEC load forecast February 21-28th – Draft study completed by March 28, 2018 – ISO Stakeholder meeting April 9, 2018 – comments by the 16th – ISO receives new operating procedures April 16, 2018 – Validate op. proc. – publish draft final report April 23, 2018 – ISO Stakeholder call May 1, 2018 – comments by the 8th – Final 2019 LCR report May 15, 2018

ISO Public Slide 8

58 / 226 2018 ISO Procurement Schedule

Per ISO Tariff and BPM - overall timeline – Final LCR Report May 15, 2018 – LSE self-guided local allocation; third week in May, 2018 – Receive new CEC coincident load forecast June 30, 2018 – ISO or CPUC to send out final local allocation; middle of July, 2018 – For any current RMR resource; LSEs to submit showings by Sept. 14, 2018 – ISO to decide on retaining units under RMR by October 1, 2018 – Final LSE showings TBD – Usually last week of October, 2018 – ISO to send a market notice out stating deficiencies in procurement (3 weeks after final showing) - about November 21, 2018 – ISO receives additional showing (30 days after market notice) – ISO to enter back-stop procurement for local reasons (if needed)

ISO Public Slide 9

59 / 226 THANK YOU Your comments and questions are welcome.

For written comments, please send to: [email protected]

Stay connected

ISO Public Page 10

60 / 226 California Independent System Operator

2023 LOCAL CAPACITY TECHNICAL ANALYSIS

FINAL REPORT AND STUDY RESULTS

May 15, 2018

61 / 226 Local Capacity Technical Analysis Overview and Study Results

I. Executive Summary

This report documents the results of the 2023 Long-Term Local Capacity Technical (LCT) Study. The LCT Study objectives, inputs, methodologies and assumptions are the same as those discussed in the 2019 LCT Study to be adopted by the CAISO and submitted to the CPUC for adoption in their 2019 Local Resource Adequacy process. Overall, the LCR trend compared with 2022, is down by about 414 MW or about 1.7%. It is worth mentioning the following areas: (1) Humboldt, Fresno and San Diego- Imperial Valley where LCR has decreased mostly due to load forecast and new transmission projects; (2) Sierra, Stockton and Bay Area where LCR has decreased mostly due to new transmission projects; (3) North Coast/North Bay, LA Basin and Big Creek/Ventura where LCR has increased mainly due to load forecast increase; (4) Kern, where the LCR has increased due to new requirements in the Wespark sub-area. The load forecast used in this study is based on the final adopted California Energy Demand Updated Forecast, 2018-2030 developed by the CEC; namely the load serving entity (LSE and balancing authority (BA) mid baseline demand with low additional achievable energy efficiency and photo voltaic (AAEE-AAPV), re-posted on 2/21/2018: http://www.energy.ca.gov/2017_energypolicy/documents/index.html#02212018. For comparison below you will find the 2019 and 2023 total LCR needs.

62 / 226 2019 Local Capacity Needs

2019 LCR Need Based 2019 LCR Need Based Qualifying Capacity on Category B on Category C with operating procedure QF/ Existing Existing Market Total Defici Total Defici Total Local Area Name Muni Capacity Capacity (MW) (MW) ency (MW) ency (MW) (MW) Needed Needed** Humboldt 0 202 202 116 0 116 165 0 165

North Coast/ 119 771 890 689 0 689 689 0 689 North Bay

Sierra 1146 1004 2150 1362 0 1362 1964 283* 2247 Stockton 144 489 633 405 5* 410 427 350* 777 Greater Bay 628 6426 7054 3670 0 3670 4461 0 4461

Greater Fresno 340 3098 3438 1406 0 1406 1670 1* 1671 Kern 13 462 475 148 6* 154 472 6* 478 LA Basin 1445 8780 10225 7968 0 7968 8116 0 8116 Big Creek/Ventura 424 4649 5073 2333 0 2333 2614 0 2614 San Diego/ Imperial 106 4252 4358 4026 0 4026 4026 0 4026 Valley Total 4365 30133 34498 22123 11 22134 24604 640 25244

2023 Local Capacity Needs

2023 LCR Need Based 2023 LCR Need Based Qualifying Capacity on Category B on Category C with operating procedure QF/ Existing Existing Market Total Defici Total Defici Total Local Area Name Muni Capacity Capacity (MW) (MW) ency (MW) ency (MW) (MW) Needed Needed** Humboldt 0 202 202 111 0 111 169 0 169

North Coast/ 119 771 890 553 0 553 553 0 553 North Bay Sierra 1146 1004 2150 1268 0 1268 1924 0 1924 Stockton 144 540 684 225 20* 245 333 106* 439

Greater Bay 627 6427 7054 3676 0 3676 4752 0 4752 Greater Fresno 340 3169 3509 1688 0 1688 1688 0 1688

Kern 13 462 475 152 6* 158 174 8* 182 LA Basin 1443 6868 8311 6793 0 6793 6793 0 6793 Big Creek/Ventura 424 3083 3507 2212 0 2212 2690 102* 2792

San Diego/ 106 4381 4487 4132 0 4132 4132 0 4132 Imperial Valley Total 4362 26907 31269 20810 26 20836 23208 216 23424

63 / 226 * No local area is “overall deficient”. Resource deficiency values result from a few deficient sub-areas; and since there are no resources that can mitigate this deficiency the numbers are carried forward into the total area needs. Resource deficient sub-area implies that in order to comply with the criteria, at summer peak, load may be shed immediately after the first contingency. ** Since “deficiency” cannot be mitigated by any available resource, the “Existing Capacity Needed” will be split among LSEs on a load share ratio during the assignment of local area resource responsibility.

The narrative for each Local Capacity Area lists important new projects included in the base cases as well as a description of reason for changes between the 2022 Long-Term LCR study and this 2023 Long-Term LCR study.

64 / 226 Table of Contents

I. Executive Summary ...... 1

II. Overview of the Study: Inputs, Outputs and Options ...... 5 A. Objectives ...... 5 B. Key Study Assumptions ...... 5 1. Inputs and Methodology ...... 5 C. Grid Reliability ...... 7 D. Application of N-1, N-1-1, and N-2 Criteria...... 8 E. Performance Criteria ...... 8 F. The Two Options Presented In This LCT Report ...... 15 1. Option 1- Meet Performance Criteria Category B ...... 15 2. Option 2- Meet Performance Criteria Category C and Incorporate Suitable Operational Solutions ...... 16

III. Assumption Details: How the Study was Conducted ...... 17 A. System Planning Criteria ...... 17 1. Power Flow Assessment: ...... 18 2. Post Transient Load Flow Assessment: ...... 19 3. Stability Assessment: ...... 19 B. Load Forecast ...... 19 1. System Forecast ...... 19 2. Base Case Load Development Method ...... 20 C. Power Flow Program Used in the LCR analysis ...... 21

IV. Locational Capacity Requirement Study Results ...... 22 A. Summary of Study Results ...... 22 B. Summary of Results by Local Area ...... 24 1. Humboldt Area...... 24 2. North Coast / North Bay Area ...... 26 3. Sierra Area ...... 29 4. Stockton Area...... 33 5. Greater Bay Area ...... 37 6. Greater Fresno Area ...... 42 7. Kern Area ...... 46 8. LA Basin Area ...... 49 9. Big Creek/Ventura Area ...... 57 10. San Diego-Imperial Valley Area ...... 61 11. Valley Electric Area ...... 69

V. Appendix A – List of physical resources by PTO, local area and market ID ...... 70

VI. Appendix B – Effectiveness factors for procurement guidance...... 118

65 / 226 II. Overview of the Study: Inputs, Outputs and Options

A. Objectives

As was the objective of all previous LCT Studies, the intent of the 2023 Long- Term LCT Study is to identify specific areas within the CAISO Balancing Authority Area that have limited import capability and determine the minimum generation capacity (MW) necessary to mitigate the local reliability problems in those areas.

B. Key Study Assumptions

1. Inputs and Methodology

The CAISO used the same Inputs and Methodology as does agreed upon by interested parties previously incorporated into the 2019 LCR Study. The following table sets forth a summary of the approved inputs and methodology that have been used in the previous 2019 LCR Study as well as this 2023 LCR Study:

66 / 226 Summary Table of Inputs and Methodology Used in this LCR Study:

Issue: How Incorporated into THIS LCR Study:

Input Assumptions:

 Transmission System The existing transmission system has been modeled, including Configuration all projects operational on or before June 1, of the study year and all other feasible operational solutions brought forth by the PTOs and as agreed to by the CAISO.  Generation Modeled The existing generation resources has been modeled and also includes all projects that will be on-line and commercial on or before June 1, of the study year  Load Forecast Uses a 1-in-10 year summer peak load forecast Methodology:

 Maximize Import Capability Import capability into the load pocket has been maximized, thus minimizing the generation required in the load pocket to meet applicable reliability requirements.  QF/Nuclear/State/Federal Units Regulatory Must-take and similarly situated units like QF/Nuclear/State/Federal resources have been modeled on-line at qualifying capacity output values for purposes of this LCR Study.  Maintaining Path Flows Path flows have been maintained below all established path ratings into the load pockets, including the 500 kV. For clarification, given the existing transmission system configuration, the only 500 kV path that flows directly into a load pocket and will, therefore, be considered in this LCR Study is the South of Lugo transfer path flowing into the LA Basin. Performance Criteria:

 Performance Level B & C, This LCR Study is being published based on Performance Level including incorporation of PTO B and Performance Level C criterion, yielding the low and high operational solutions range LCR scenarios. In addition, the CAISO will incorporate all new projects and other feasible and CAISO-approved operational solutions brought forth by the PTOs that can be operational on or before June 1, of the study year. Any such solutions that can reduce the need for procurement to meet the Performance Level C criteria will be incorporated into the LCR Study. Load Pocket:  Fixed Boundary, including This LCR Study has been produced based on load pockets limited reference to published defined by a fixed boundary. The CAISO only publishes effectiveness factors effectiveness factors where they are useful in facilitating procurement where excess capacity exists within a load pocket.

Further details regarding the 2019 as well as 2023 LCR Study methodology and assumptions are provided in Section III, below.

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C. Grid Reliability

Service reliability builds from grid reliability because grid reliability is reflected in the Reliability Standards of the North American Electric Reliability Council (NERC) and the Western Electricity Coordinating Council (“WECC”) Regional Criteria (collectively “Reliability Standards”). The Reliability Standards apply to the interconnected electric system in the United States and are intended to address the reality that within an integrated network, whatever one Balancing Authority Area does can affect the reliability of other Balancing Authority Areas. Consistent with the mandatory nature of the Reliability Standards, the CAISO is under a statutory obligation to ensure efficient use and reliable operation of the transmission grid consistent with achievement of the Reliability Standards.1 The CAISO is further under an obligation, pursuant to its FERC- approved Transmission Control Agreement, to secure compliance with all “Applicable Reliability Criteria.” Applicable Reliability Criteria consists of the Reliability Standards as well as reliability criteria adopted by the CAISO (Grid Planning Standards). The Reliability Standards define reliability on interconnected electric systems using the terms “adequacy” and “security.” “Adequacy” is the ability of the electric systems to supply the aggregate electrical demand and energy requirements of their customers at all times, taking into account physical characteristics of the transmission system such as transmission ratings and scheduled and reasonably expected unscheduled outages of system elements. “Security” is the ability of the electric systems to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. The Reliability Standards are organized by Performance Categories. Certain categories require that the grid operator not only ensure that grid integrity is maintained under certain adverse system conditions (e.g., security), but also that all customers continue to receive electric supply to meet demand (e.g., adequacy). In that case, grid reliability and service reliability would overlap. But there are other levels of performance where security can be maintained without ensuring adequacy.

1 Pub. Utilities Code § 345

68 / 226 D. Application of N-1, N-1-1, and N-2 Criteria

The CAISO will maintain the system in a safe operating mode at all times. This obligation translates into respecting the Reliability Criteria at all times, for example during normal operating conditions (N-0) the CAISO must protect for all single contingencies (N-1) and common mode (N-2) double line outages. Also, after a single contingency, the CAISO must re-adjust the system to support the loss of the next most stringent contingency. This is referred to as the N-1-1 condition. The N-1-1 vs N-2 terminology was introduced only as a temporal differentiation between two existing NERC Category C events. N-1-1 represents NERC Category C3 (“category B contingency, manual system adjustment, followed by another category B contingency”). The N-2 represents NERC Category C5 (“any two circuits of a multiple circuit tower line”) as well as WECC-S2 (for 500 kV only) (“any two circuits in the same right-of-way”) with no manual system adjustment between the two contingencies.

E. Performance Criteria

As set forth on the Summary Table of Inputs and Methodology, this LCR Report is based on NERC Performance Level B and Performance Level C criterion. The NERC Standards refer mainly to thermal overloads. However, the CAISO also tests the electric system in regards to the dynamic and reactive margin compliance with the existing WECC standards for the same NERC performance levels. These Performance Levels can be described as follows:

a. Performance Criteria- Category B

Category B describes the system performance that is expected immediately following the loss of a single transmission element, such as a transmission circuit, a generator, or a transformer.

69 / 226 Category B system performance requires that all thermal and voltage limits must be within their “Applicable Rating,” which, in this case, are the emergency ratings as generally determined by the PTO or facility owner. Applicable Rating includes a temporal element such that emergency ratings can only be maintained for certain duration. Under this category, load cannot be shed in order to assure the Applicable Ratings are met however there is no guarantee that facilities are returned to within normal ratings or to a state where it is safe to continue to operate the system in a reliable manner such that the next element out will not cause a violation of the Applicable Ratings.

b. Performance Criteria- Category C

The NERC Planning Standards require system operators to “look forward” to make sure they safely prepare for the “next” N-1 following the loss of the “first” N-1 (stay within Applicable Ratings after the “next” N-1). This is commonly referred to as N-1-1. Because it is assumed that some time exists between the “first” and “next” element losses, operating personnel may make any reasonable and feasible adjustments to the system to prepare for the loss of the second element, including, operating procedures, dispatching generation, moving load from one substation to another to reduce equipment loading, dispatching operating personnel to specific station locations to manually adjust load from the substation site, or installing a “Special Protection Scheme” that would remove pre-identified load from service upon the loss of the “next “ element.2 All Category C requirements in this report refer to situations when in real time (N-0) or after the first contingency (N-1) the system requires additional readjustment in

2 A Special Protection Scheme is typically proposed as an operational solution that does not require additional generation and permits operators to effectively prepare for the next event as well as ensure security should the next event occur. However, these systems have their own risks, which limit the extent to which they could be deployed as a solution for grid reliability augmentation. While they provide the value of protecting against the next event without the need for pre-contingency load shedding, they add points of potential failure to the transmission network. This increases the potential for load interruptions because sometimes these systems will operate when not required and other times they will not operate when needed.

70 / 226 order to prepare for the next worst contingency. In this time frame, load drop is not allowed per existing planning criteria. Generally, Category C describes system performance that is expected following the loss of two or more system elements. This loss of two elements is generally expected to happen simultaneously, referred to as N-2. It should be noted that once the “next” element is lost after the first contingency, as discussed above under the Performance Criteria B, N-1-1 scenario, the event is effectively a Category C. As noted above, depending on system design and expected system impacts, the planned and controlled interruption of supply to customers (load shedding), the removal from service of certain generators and curtailment of exports may be utilized to maintain grid “security.”

c. CAISO Statutory Obligation Regarding Safe Operation

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A (N-0) C5 (N-2) Loading within A/R (normal) as well as making sure the system can Loading support the loss of the most stringent next single element or credible Within A/R double and be within post-contingency A/R (emergency). (emergency)

Planned and Load Shedding Not Allowed Controlled Load Shedding ------Example (30 min)------Allowed A (N-0) B (N-1) C3 (N-1-1) Loading Loading Manual adjust per NERC Loading Within A/R Within A/R C3 in order to support the Within A/R (normal) (emergency) Loss of the next element. (emergency)

First N-1 Second occurs trip occurs “LCR Category B”

“LCR Category C”

The following definitions guide the CAISO’s interpretation of the Reliability Criteria governing safe mode operation and are used in this LCT Study:

Applicable Rating: This represents the equipment rating that will be used under certain contingency conditions.

Normal rating is to be used under normal conditions. Long-term emergency ratings, if available, will be used in all emergency conditions as long as “system readjustment” is provided in the amount of time given (specific to each element) to reduce the flow to within the normal ratings. If not available, the normal rating is to be used. Short-term emergency ratings, if available, can be used as long as “system readjustment” is provided in the “short-time” available in order to reduce the flow to within the long-term emergency ratings where the element can be kept for another

72 / 226 length of time (specific to each element) before the flow needs to be reduced the below the normal ratings. If not available long-term emergency rating should be used. Temperature-adjusted ratings shall not be used because this is a year-ahead study, not a real-time tool, and as such the worst-case scenario must be covered. In case temperature-adjusted ratings are the only ratings available then the minimum rating (highest temperature) given the study conditions shall be used. CAISO Transmission Register is the only official keeper of all existing ratings mentioned above. Ratings for future projects provided by PTO and agreed upon by the CAISO shall be used. Other short-term ratings not included in the CAISO Transmission Register may be used as long as they are engineered, studied and enforced through clear operating procedures that can be followed by real-time operators. Path Ratings need to be maintained within their limits in order to assure that proper capacity is available in order to operate the system in real-time in a safe operating zone.

Controlled load drop:

This is achieved with the use of a Special Protection Scheme.

Planned load drop:

This is achieved when the most limiting equipment has short-term emergency ratings AND the operators have an operating procedure that clearly describes the actions that need to be taken in order to shed load.

Special Protection Scheme:

All known SPS shall be assumed. New SPS must be verified and approved by the CAISO and must comply with the new SPS guideline described in the CAISO Planning Standards.

System Readjustment: This represents the actions taken by operators in order to bring the system within a safe operating zone after any given contingency in the system.

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Actions that can be taken as system readjustment after a single contingency (Category B): 1. System configuration change – based on validated and approved operating procedures 2. Generation re-dispatch a. Decrease generation (up to 1150 MW) – limit given by single contingency SPS as part of the CAISO Grid Planning standards (ISO G4) b. Increase generation – this generation will become part of the LCR need

Actions, which shall not be taken as system readjustment after a single contingency (Category B): 1. Load drop – based on the intent of the CAISO/WECC and NERC criteria for category B contingencies.

The NERC Transmission Planning Standards footnote mentions that load shedding can be done after a category B event in certain local areas in order to maintain compliance with performance criteria. However, the main body of the criteria spells out that no dropping of load should be done following a single contingency. All stakeholders and the CAISO agree that no involuntary interruption of load should be done immediately after a single contingency. Further, the CAISO and stakeholders now agree on the viability of dropping load as part of the system readjustment period – in order to protect for the next most limiting contingency. After a single contingency, it is understood that the system is in a Category B condition and the system should be planned based on the body of the criteria with no shedding of load regardless of whether it is done immediately or in 15-30 minute after the original contingency. Category C conditions only arrive after the second contingency has happened; at that point in time, shedding load is allowed in a planned and controlled manner.

A robust California transmission system should be, and under the LCT Study is being, planned based on the main body of the criteria, not the footnote regarding Category B

74 / 226 contingencies. Therefore, if there are available resources in the area, they are looked to meet reliability needs (and included in the LCR requirement) before resorting to involuntary load curtailment. The footnote may be applied for criteria compliance issues only where there are no resources available in the area.

Time allowed for manual readjustment:

Tariff Section 40.3.1.1, requires the CAISO, in performing the Local Capacity Technical Study, to apply the following reliability criterion:

Time Allowed for Manual Adjustment: This is the amount of time required for the Operator to take all actions necessary to prepare the system for the next Contingency. The time should not be more than thirty (30) minutes.

The CAISO Planning Standards also impose this manual readjustment requirement. As a parameter of the Local Capacity Technical Study, the CAISO must assume that as the system operator the CAISO will have sufficient time to: (1) make an informed assessment of system conditions after a contingency has occurred; (2) identify available resources and make prudent decisions about the most effective system redispatch; (3) manually readjust the system within safe operating limits after a first contingency to be prepared for the next contingency; and (4) allow sufficient time for resources to ramp and respond according to the operator’s redispatch instructions. This all must be accomplished within 30 minutes.

Local capacity resources can meet this requirement by either (1) responding with sufficient speed, allowing the operator the necessary time to assess and redispatch resources to effectively reposition the system within 30 minutes after the first contingency, or (2) have sufficient energy available for frequent dispatch on a pre- contingency basis to ensure the operator can meet minimum online commitment constraints or reposition the system within 30 minutes after the first contingency occurs.

75 / 226 Accordingly, when evaluating resources that satisfy the requirements of the CAISO Local Capacity Technical Study, the CAISO assumes that local capacity resources need to be available in no longer than 20 minutes so the CAISO and demand response providers have a reasonable opportunity to perform their respective and necessary tasks and enable the CAISO to reposition the system within the 30 minutes in accordance with applicable reliability criteria.

F. The Two Options Presented In This LCT Report

This LCT Study sets forth different solution “options” with varying ranges of potential service reliability consistent with CAISO’s Reliability Criteria. The CAISO applies Option 2 for its purposes of identifying necessary local capacity needs and the corresponding potential scope of its backstop authority. Nevertheless, the CAISO continues to provide Option 1 as a point of reference for the CPUC and Local Regulatory Authorities in considering procurement targets for their jurisdictional LSEs.

1. Option 1- Meet Performance Criteria Category B

Option 1 is a service reliability level that reflects generation capacity that must be available to comply with reliability standards immediately after a NERC Category B given that load cannot be removed to meet this performance standard under Reliability Criteria. However, this capacity amount implicitly relies on load interruption as the only means of meeting any Reliability Criteria that is beyond the loss of a single transmission element (N-1). These situations will likely require substantial load interruptions in order to maintain system continuity and alleviate equipment overloads prior to the actual occurrence of the second contingency.3

3 This potential for pre-contingency load shedding also occurs because real time operators must prepare for the loss of a common mode N-2 at all times.

76 / 226 2. Option 2- Meet Performance Criteria Category C and Incorporate Suitable Operational Solutions

Option 2 is a service reliability level that reflects generation capacity that is needed to readjust the system to prepare for the loss of a second transmission element (N-1-1) using generation capacity after considering all reasonable and feasible operating solutions (including those involving customer load interruption) developed and approved by the CAISO, in consultation with the PTOs. Under this option, there is no expected load interruption to end-use customers under normal or single contingency conditions as the CAISO operators prepare for the second contingency. However, the customer load may be interrupted in the event the second contingency occurs. As noted, Option 2 is the local capacity level that the CAISO requires to reliably operate the grid per NERC, WECC and CAISO standards. As such, the CAISO recommends adoption of this Option to guide resource adequacy procurement.

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III. Assumption Details: How the Study was Conducted

A. System Planning Criteria

The following table provides a comparison of system planning criteria, based on the NERC performance standards, used in the study:

Table 4: Criteria Comparison ISO Grid Old Local Contingency Component(s) Planning RMR Capacity Criteria Criteria Criteria A – No Contingencies X X X

B – Loss of a single element 1 1. Generator (G-1) X X X 2. Transmission Circuit (L-1) X X X1 2 3. Transformer (T-1) X X X1,2 4. Single Pole (dc) Line X X X1 5. G-1 system readjusted L-1 X X X

C – Loss of two or more elements 1. Bus Section X 2. Breaker (failure or internal fault) X 3. L-1 system readjusted G-1 X X 3. G-1 system readjusted T-1 or T-1 system readjusted G-1 X X 3. L-1 system readjusted T-1 or T-1 system readjusted L-1 X X 3. G-1 system readjusted G-1 X X 3. L-1 system readjusted L-1 X X 3. T-1 system readjusted T-1 X 4. Bipolar (dc) Line X X 5. Two circuits (Common Mode) L-2 X X 6. SLG fault (stuck breaker or protection failure) for G-1 X 7. SLG fault (stuck breaker or protection failure) for L-1 X 8. SLG fault (stuck breaker or protection failure) for T-1 X 9. SLG fault (stuck breaker or protection failure) for Bus section X WECC-S3. Two generators (Common Mode) G-2 X3 X

D – Extreme event – loss of two or more elements Any B1-4 system readjusted (Common Mode) L-2 X4 X3 All other extreme combinations D1-14. X4 1 System must be able to readjust to a safe operating zone in order to be able to support the loss of the next contingency. 2 A thermal or voltage criterion violation resulting from a transformer outage may not be cause for a local area reliability requirement if the violation is considered marginal (e.g. acceptable loss of facility life or low voltage), otherwise, such a violation will necessitate creation of a requirement. 3 Evaluate for risks and consequence, per NERC standards. No voltage collapse or dynamic instability allowed. 4 Evaluate for risks and consequence, per NERC standards.

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A significant number of simulations were run to determine the most critical contingencies within each Local Capacity Area. Using power flow, post-transient load flow, and stability assessment tools, the system performance results of all the contingencies that were studied were measured against the system performance requirements defined by the criteria shown in Table 4. Where the specific system performance requirements were not met, generation was adjusted such that the minimum amount of generation required to meet the criteria was determined in the Local Capacity Area. The following describes how the criteria were tested for the specific type of analysis performed.

1. Power Flow Assessment:

Contingencies Thermal Criteria3 Voltage Criteria4 Generating unit 1, 6 Applicable Rating Applicable Rating Transmission line 1, 6 Applicable Rating Applicable Rating Transformer 1, 6 Applicable Rating5 Applicable Rating5 (G-1)(L-1) 2, 6 Applicable Rating Applicable Rating Overlapping 6, 7 Applicable Rating Applicable Rating

1 All single contingency outages (i.e. generating unit, transmission line or transformer) will be simulated on Participating Transmission Owners’ local area systems. 2 Key generating unit out, system readjusted, followed by a line outage. This overlapping outage is considered a single contingency within the ISO Grid Planning Criteria. Therefore, load dropping for an overlapping G-1, L-1 scenario is not permitted. 3 Applicable Rating – Based on CAISO Transmission Register or facility upgrade plans including established Path ratings. 4 Applicable Rating – CAISO Grid Planning Criteria or facility owner criteria as appropriate including established Path ratings. 5 A thermal or voltage criterion violation resulting from a transformer outage may not be cause for a local area reliability requirement if the violation is considered marginal (e.g. acceptable loss of facility life or low voltage), otherwise, such a violation will necessitate creation of a requirement. 6 Following the first contingency (N-1), the generation must be sufficient to allow the operators to bring the system back to within acceptable (normal) operating range (voltage and loading) and/or appropriate OTC following the studied outage conditions. 7 During normal operation or following the first contingency (N-1), the generation must be sufficient to allow the operators to prepare for the next worst N-1 or

79 / 226 common mode N-2 without pre-contingency interruptible or firm load shedding. SPS/RAS/Safety Nets may be utilized to satisfy the criteria after the second N-1 or common mode N-2 except if the problem is of a thermal nature such that short-term ratings could be utilized to provide the operators time to shed either interruptible or firm load. T-2s (two transformer bank outages) would be excluded from the criteria.

2. Post Transient Load Flow Assessment:

Contingencies Reactive Margin Criteria 2 Selected 1 Applicable Rating

1 If power flow results indicate significant low voltages for a given power flow contingency, simulate that outage using the post transient load flow program. The post-transient assessment will develop appropriate Q/V and/or P/V curves. 2 Applicable Rating – positive margin based on the higher of imports or load increase by 5% for N-1 contingencies, and 2.5% for N-2 contingencies.

3. Stability Assessment:

Contingencies Stability Criteria 2 Selected 1 Applicable Rating

1 Base on historical information, engineering judgment and/or if power flow or post transient study results indicate significant low voltages or marginal reactive margin for a given contingency. 2 Applicable Rating – CAISO Grid Planning Criteria or facility owner criteria as appropriate.

B. Load Forecast

1. System Forecast

The California Energy Commission (CEC) derives the load forecast at the system and Participating Transmission Owner (PTO) levels. This relevant CEC forecast is then distributed across the entire system, down to the local area, division and substation level. The PTOs use an econometric equation to forecast the system load. The predominant parameters affecting the system load are (1) number of households, (2) economic activity (gross metropolitan products, GMP), (3) temperature and (4) increased energy efficiency and distributed generation programs.

80 / 226 2. Base Case Load Development Method

The method used to develop the load in the base case is a melding process that extracts, adjusts and modifies the information from the system, distribution and municipal utility forecasts. The melding process consists of two parts: Part 1 deals with the PTO load and Part 2 deals with the municipal utility load. There may be small differences between the methodologies used by each PTO to disaggregate the CEC load forecast to their level of local area as well as bar-bus model.

a. PTO Loads in Base Case

The methods used to determine the PTO loads are, for the most part, similar. One part of the method deals with the determination of the division4 loads that would meet the requirements of 1-in-5 or 1-in-10 system or area base cases and the other part deals with the allocation of the division load to the transmission buses.

i. Determination of division loads

The annual division load is determined by summing the previous year division load and the current division load growth. Thus, the key steps are the determination of the initial year division load and the annual load growth. The initial year for the base case development method is based heavily on recorded data. The division load growth in the system base case is determined in two steps. First, the total PTO load growth for the year is determined, as the product of the PTO load and the load growth rate from the system load forecast. Then this total PTO load growth is allocated to the division, based on the relative magnitude of the load growth projected for the divisions by the distribution planners. For example, for the 1-in-10 area base case, the division load growth determined for the system base case is adjusted to the 1-in-10 temperature using the load temperature relation determined from the latest peak load and temperature data of the division.

ii. Allocation of division load to transmission bus level

4 Each PTO divides its territory in a number of smaller area named divisions. These are usually smaller and compact areas that have the same temperature profile.

81 / 226 Since the loads in the base case are modeled at the various transmission buses, the division loads developed must be allocated to those buses. The allocation process is different depending on the load types. For the most part, each PTO classifies its loads into four types: conforming, non-conforming, self-generation and generation-plant loads. Since the non-conforming and self-generation loads are assumed to not vary with temperature, their magnitude would be the same in the system or area base cases of the same year. The remaining load (the total division load developed above, less the quantity of non-conforming and self-generation load) is the conforming load. The remaining load is allocated to the transmission buses based on the relative magnitude of the distribution forecast. The summation of all base case loads is generally higher than the load forecast because some load, i.e., self-generation and generation-plant, are behind the meter and must be modeled in the base cases. However, for the most part, metered or aggregated data with telemetry is used to come up with the load forecast.

b. Municipal Loads in Base Case

The municipal utility forecasts that have been provided to the CEC and PTOs for the purposes of their base cases were also used for this study.

C. Power Flow Program Used in the LCR analysis

The technical studies were conducted using General Electric’s Power System Load Flow (GE PSLF) program version 21.04 and PowerGem’s Transmission Adequacy and Reliability Assessment (TARA) program version 1702. This GE PSLF program is available directly from GE or through the Western System Electricity Council (WECC) to any member and TARA program is commercially available. To evaluate Local Capacity Areas, the starting base case was adjusted to reflect the latest generation and transmission projects as well as the one-in-ten-year peak load forecast for each Local Capacity Area as provided to the CAISO by the PTOs. Electronic contingency files provided by the PTOs were utilized to perform the numerous contingencies required to identify the LCR. These contingency files include remedial action and special protection schemes that are expected to be in operation

82 / 226 during the year of study. A CAISO created EPCL (a GE programming language contained within the GE PSLF package) routine and/or TARA software were used to run the combination of contingencies; however, other routines are available from WECC with the GE PSFL package or can be developed by third parties to identify the most limiting combination of contingencies requiring the highest amount of generation within the local area to maintain power flows within applicable ratings.

IV. Locational Capacity Requirement Study Results

A. Summary of Study Results

LCR is defined as the amount of resource capacity that is needed within a Local Capacity Area to reliably serve the load located within this area. The results of the CAISO’s analysis are summarized in the Executive Summary Tables.

Table 5: 2019 Local Capacity Needs vs. Peak Load and Local Area Resources

2019 Peak Load 2019 LCR Total Dependable 2019 LCR as % Total LCRiii. (1 in10)e as % of Local Area of Total Area (MW) (MW) Peak Load Resources (MW) Resources

Humboldt 165 187 88% 202 82% North Coast/North Bay 689 1465 47% 890 77% Sierra 2247 1758 128% 2150 105%** Stockton 777 1174 66% 633 123%** Greater Bay 4461 10230 44% 7054 63% Greater Fresno 1671 3070 54% 3438 49%** Kern 478 1088 44% 475 101%** LA Basin 8116 19266 42% 10225 79% Big Creek/Ventura 2614 5162 51% 5073 52% San Diego/Imperial 4026 4412 91% 4358 92% Valley Total 25244 47812* 53%* 34498 73%

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Table 6: 2023 Local Capacity Needs vs. Peak Load and Local Area Resources

2023 Peak Load 2023 LCR Total Dependable 2023 LCR as % Total LCRiv. (1 in10)e as % of Local Area of Total Area (MW) (MW) Peak Load Resources (MW) Resources

Humboldt 169 188 90% 202 84% North Coast/North Bay 553 1524 36% 890 62% Sierra 1924 1822 106% 2150 89% Stockton 439 1227 36% 684 64%** Greater Bay 4752 10441 46% 7054 67% Greater Fresno 1688 3231 52% 3509 48% Kern 182 1140 16% 475 38%** LA Basin 6793 20072 34% 8311 82% Big Creek/Ventura 2792 5169 54% 3507 80%** San Diego/Imperial 4132 4554 91% 4487 92% Valley Total 23424 49368* 47%* 31269 75%

* Value shown only illustrative, since each local area peaks at a different time.

** Resource deficient LCA (or with sub-area that are deficient) – deficiency included in LCR. Resource deficient area implies that in order to comply with the criteria, at summer peak, load must be shed immediately after the first contingency.

Tables 5 and 6 shows how much of the Local Capacity Area load is dependent on local resources and how many local resources must be available in order to serve the load in those Local Capacity Areas in a manner consistent with the Reliability Criteria. These tables also indicate where new transmission projects, new resource additions or demand side management programs would be most useful in order to reduce the dependency on existing, generally older and less efficient local area resources. The term “Qualifying Capacity” used in this report is the “Net Qualifying Capacity” (“NQC”) posted on the CAISO web site at: http://www.caiso.com/planning/Pages/ReliabilityRequirements/Default.aspx The NQC list includes the area (if applicable) where each resource is located for units already operational. Neither the NQC list nor this report incorporates Demand Side Management programs and their related NQC. Units scheduled to become

84 / 226 operational before June 1 of 2023 have been included in this 2023 Long-Term LCR Report and added to the total NQC values for those respective areas (see detail write- up for each area). Regarding the main tables up front (page 2), the first column, “Qualifying Capacity,” reflects two sets of resources. The first set is comprised of resources that would normally be expected to be on-line such as Municipal and Regulatory Must-take resources (state, federal, QFs, wind and nuclear units). The second set is “market” resources. The second column, “YEAR LCR Requirement Based on Category B” identifies the local capacity requirements, and deficiencies that must be addressed, in order to achieve a service reliability level based on Performance Criteria- Category B. The third column, “YEAR LCR Requirement Based on Category C with Operating Procedure”, sets forth the local capacity requirements, and deficiencies that must be addressed, necessary to attain a service reliability level based on Performance Criteria- Category C with operational solutions.

B. Summary of Results by Local Area

Each Local Capacity Area’s overall requirement is determined by also achieving each sub-area requirement. Because these areas are a part of the interconnected electric system, the total for each Local Capacity Area is not simply a summation of the sub-area needs. For example, some sub-areas may overlap and therefore the same units may count for meeting the needs in both sub-areas.

1. Humboldt Area

Area Definition:

The transmission tie lines into the area include:

1) Bridgeville-Cottonwood 115 kV line #1 2) Humboldt-Trinity 115 kV line #1

85 / 226 3) Willits-Garberville 60 kV line #1 4) Trinity-Maple Creek 60 kV line #1

The substations that delineate the Humboldt Area are:

1) Bridgeville and Low Gap are in, Cottonwood is out 2) Humboldt is in Trinity is out 3) Willits is out, Kekawaka and Garberville are in 4) Trinity and Ridge Cabin are out, Maple Creek is in

Load: Total 2022 busload within the defined area: 196 MW with -19 MW of AAEE and 12 MW of losses resulting in total load + losses of 188 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Maple Creek Reactive Support 2. Garberville Reactive Support 3. Bridgeville 115/60 kV #1 transformer replacement

Critical Contingency Analysis Summary:

Humboldt Overall: The most critical contingency for the Humboldt area is the outage of the Cottonwood- Bridgeville 115 kV line overlapping with an outage of the gen-tie (Humboldt-Humboldt Bay 115 kV Line) from Humboldt Bay Power Plant to units 1-4. The local area limitation is potential overload on the Humboldt -Trinity 115 kV Line. This contingency establishes a local capacity need of 169 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this area.

The single most critical contingency for the Humboldt area is the outage of the Cottonwood-Bridgeville 115 kV line with one of the Humboldt Bay Power Plant units already out of service, which could potentially overload the Humboldt -Trinity 115 kV line. This contingency establishes a local capacity need of 111 MW in 2023.

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Effectiveness factors: For most helpful procurement information please read procedure 2210Z Effectiveness Factors under 7110 (T-138Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Changes compared to last year’s results:

The load forecast decreased by 2 MW from 2022 to 2023 and the total LCR has remained the same.

Humboldt Overall Requirements: 2023 QF/Selfgen Market Max. Qualifying (MW) (MW) Capacity (MW) Available generation 0 202 202

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single)5 111 0 111 Category C (Multiple)6 169 0 169

2. North Coast / North Bay Area

Area Definition:

The transmission tie facilities coming into the North Coast/North Bay area are:

1) Cortina-Mendocino 115 kV Line 2) Cortina-Eagle Rock 115 kV Line 3) Willits-Garberville 60 kV line #1 4) Vaca Dixon-Lakeville 230 kV line #1 5) Tulucay-Vaca Dixon 230 kV line #1

5 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 6 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

87 / 226 6) Lakeville-Sobrante 230 kV line #1 7) Ignacio-Sobrante 230 kV line #1

The substations that delineate the North Coast/North Bay area are:

1) Cortina is out, Mendocino and Indian Valley are in 2) Cortina is out, Eagle Rock, Highlands and Homestake are in 3) Willits and Lytonville are in, Kekawaka and Garberville are out 4) Vaca Dixon is out, Lakeville is in 5) Tulucay is in, Vaca Dixon is out 6) Lakeville is in, Sobrante is out 7) Ignacio is in, Sobrante and Crocket are out

Load:

Total 2023 busload within the defined area: 1557 MW with -60 MW of AAEE, -15 MW BTM-PV, and 42 MW of losses resulting in total load + losses of 1524 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Vaca Dixon-Lakeville 230 kV Corridor Series Compensation

Critical Contingency Analysis Summary:

Eagle Rock Sub-area The most critical overlapping contingency is an outage of the Geysers #3 - Geyser #5 115 kV line and the Cortina-Mendocino 115 kV line. The sub-area area limitation is thermal overloading of the Eagle Rock-Cortina 115 kV line. This limiting contingency establishes a local capacity need of 257 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

The most critical single contingency is an outage of the Cortina-Mendocino 115 kV transmission line with Geysers 11 unit out of service. The sub-area limitation is thermal overloading of the parallel Eagle Rock-Cortina 115 kV line. This limiting contingency establishes a local capacity need of 238 MW in 2023.

88 / 226 Effectiveness factors:

See Appendix B - Table titled Eagle Rock.

For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7120 (T-151Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Fulton Sub-area The most critical overlapping contingency is the outage of the Fulton-Ignacio 230 kV line #1 and the Fulton-Lakeville 230 kV line #1. The sub-area area limitation is thermal overloading of Lakeville # 2 60 kV line (Lakeville-Petaluma A – Cotati 60 kV). This limiting contingency establishes a local capacity need of 553 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area. All of the units required to meet the Eagle Rock pocket count towards the Fulton total requirement.

Effectiveness factors: See Appendix B – Table titled Fulton.

Lakeville Sub-area (North Coast/North Bay Overall) The most limiting non-binding contingency for the North Coast/North Bay Area is an outage of Vaca Dixon-Tulucay 230 kV line and Delta Energy Center power plant being out of service. The area limitation is thermal overloading of the Vaca Dixon-Lakeville 230 kV line with series compensation included.

Effectiveness factors: See Appendix B – Table tilted Lakeville.

Changes compared to last year’s results:

Overall the load forecast went up by 275 MW compared to 2022. The overall LCR requirement went up by 113 MW as a result of load increase in the Fulton sub-area.

89 / 226 North Coast/North Bay Overall Requirements: 2023 QF/Selfgen Muni Market Max. Qualifying (MW) (MW) (MW) Capacity (MW) Available generation 6 113 771 890

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category P1 (Single)7 553 0 553 Category P7 (Multiple)8 553 0 553

3. Sierra Area

Area Definition:

The transmission tie lines into the Sierra Area are: 1) Table Mountain-Rio Oso 230 kV line 2) Table Mountain-Palermo 230 kV line 3) Table Mt-Pease 60 kV line 4) Caribou-Palermo 115 kV line 5) Drum-Summit 115 kV line #1 6) Drum-Summit 115 kV line #2 7) Spaulding-Summit 60 kV line 8) Brighton-Bellota 230 kV line 9) Rio Oso-Lockeford 230 kV line 10) Gold Hill-Eight Mile Road 230 kV line 11) Lodi-Eight Mile Road 230 kV line 12) Gold Hill-Lake 230 kV line The substations that delineate the Sierra Area are: 1) Table Mountain is out Rio Oso is in 2) Table Mountain is out Palermo is in 3) Table Mt is out Pease is in 4) Caribou is out Palermo is in 5) Drum is in Summit is out 6) Drum is in Summit is out

7 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 8 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

90 / 226 7) Spaulding is in Summit is out 8) Brighton is in Bellota is out 9) Rio Oso is in Lockeford is out 10) Gold Hill is in Eight Mile is out 11) Lodi is in Eight Mile is out 12) Gold Hill is in Lake is out

Load:

Total 2023 busload within the defined area: 1819 MW with -66 MW of AAEE, -18 MW of BTM-PV, and 87 MW of losses resulting in total load + losses of 1822 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Gold Hill-Missouri Flat #1 and #2 115 kV line reconductoring 2. Rio Oso #1 and #2 230/115 kV transformer replacement 3. Pease 115/60 kV transformer addition 4. South of Palermo 115 kV Reinforcement

Critical Contingency Analysis Summary:

Placerville Sub-area No requirements due to the Missouri Flat-Gold Hill 115 kV lines reconductoring project.

Placer Sub-area The most critical contingency is the loss of the Gold Hill-Placer #1 115 kV line with Chicago Park unit out of service. The area limitation is thermal overloading of the Drum-Higgins 115 kV line. This limiting contingency establishes a local capacity need of 89 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area (Chicago Park, Dutch Flat #1, Wise units 1&2, Newcastle, and Halsey) have the same effectiveness factor.

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Pease Sub-area The most critical contingency is the loss of the Palermo-Pease 115 kV line followed by Pease-Rio Oso 115 kV line. The area limitation is thermal overloading of the Table Mountain-Pease 60 kV line. This limiting contingency establishes a LCR of 75 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Drum-Rio Oso Sub-area No requirement due to the Rio Oso 230/115 kV Transformer Upgrade project.

South of Rio Oso Sub-area The most critical contingency is the loss of the Rio Oso-Gold Hill 230 kV line followed by loss of the Rio Oso-Brighton #1 230 kV line with potential thermal overload of the Rio Oso-Atlantic 230 kV line. This limiting contingency establishes a LCR of 554 MW in 2023 as the minimum capacity necessary for reliable load serving capability.

The single most critical contingency is the loss of the Rio Oso-Gold Hill 230 kV line with Ralston unit out of service. The area limitation is thermal overloading of the Rio Oso- Atlantic 230 kV line. This limiting contingency establishes a LCR of 416 MW in 2023.

Effectiveness factors: See Appendix B - Table titled Rio Oso.

For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7230 (T-165Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

South of Palermo Sub-area No additional requirement beyond those established by Pease and South of Rio Oso.

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South of Table Mountain Sub-area The most critical contingency is the loss of the Table Mountain-Rio Oso and Table Mountain-Palermo 230 kV double circuit tower line potentially overloading the Caribou-Palermo 115 kV line. This limitation establishes an LCR of 1924 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this area.

The most critical single contingency is the loss of the Table Mountain-Palermo 230 kV line with Belden unit out of service potentially overloading the Table Mountain-Rio Oso 230 kV line. This limiting contingency establishes a local capacity need of 1268 MW.

Effectiveness factors: See Appendix B - Table titled South of Table Mountain. For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7230 (T-165Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Changes compared to last year’s results: The load forecast went up by 8 MW as compared to 2022. Overall the total LCR for the Sierra area has decreased by 43 MW due to new transmission projects.

Sierra Overall Requirements: 2023 QF Muni Market Max. Qualifying (MW) (MW) (MW) Capacity (MW) Available generation 38 1108 1004 2150

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single)9 1268 0 1268 Category C (Multiple)10 1924 0 1924

9 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 10 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

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4. Stockton Area

The LCR requirement for the Stockton Area is driven by the sum of the requirements for the Tesla-Bellota, Lockeford and Weber sub-areas.

Area Definition:

Tesla-Bellota Sub-Area Definition The transmission facilities that establish the boundary of the Tesla-Bellota sub-area are: 1) Bellota 230/115 kV Transformer #1 2) Bellota 230/115 kV Transformer #2 3) Tesla-Tracy 115 kV Line 4) Tesla-Salado 115 kV Line 5) Tesla-Salado-Manteca 115 kV line 6) Tesla-Schulte #1 115 kV Line 7) Tesla-Schulte #2 115kV line 8) Tesla-Vierra 115 kV Line The substations that delineate the Tesla-Bellota Sub-area are: 1) Bellota 230 kV is out Bellota 115 kV is in 2) Bellota 230 kV is out Bellota 115 kV is in 3) Tesla is out Tracy is in 4) Tesla is out Salado is in 5) Tesla is out Salado and Manteca are in 6) Tesla is out Schulte is in 7) Tesla is out Schulte is in 8) Tesla is out Thermal Energy is in

Lockeford Sub-Area Definition

The transmission facilities that establish the boundary of the Lockeford sub-area are: 1) Lockeford-Industrial 60 kV line 2) Lockeford-Lodi #1 60 kV line 3) Lockeford-Lodi #2 60 kV line 4) Lockeford-Lodi #3 60 kV line The substations that delineate the Lockeford Sub-area are: 1) Lockeford is out Industrial is in 2) Lockeford is out Lodi is in

94 / 226 3) Lockeford is out Lodi is in 4) Lockeford is out Lodi is in

Weber Sub-Area Definition

The transmission facilities that establish the boundary of the Weber Sub-area are: 1) Weber 230/60 kV Transformer #1 2) Weber 230/60 kV Transformer #2 The substations that delineate the Weber Sub-area are: 1) Weber 230 kV is out Weber 60 kV is in 2) Weber 230 kV is out Weber 60 kV is in

Load:

Total 2023 busload within the defined area: 1278 MW with -63 MW of AAEE, -8 MW of BTM-PV, and 20 MW of losses resulting in total load + losses of 1227 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Weber-Stockton “A” #1 and #2 60 kV Reconductoring 2. Ripon 115 kV line 3. Vierra 115 kV Looping Project

Critical Contingency Analysis Summary:

Stanislaus Sub-area The critical contingency for the Stanislaus sub-area is the loss of Bellota-Riverbank- Melones 115 kV circuit with Stanislaus PH out of service. The area limitation is thermal overloading of the River Bank Jct.-Manteca 115 kV line. This limiting contingency establishes a local capacity need of 147 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

95 / 226 Tesla-Bellota Sub-area The most critical contingency for the Tesla-Bellota pocket is the loss of Schulte-Kasson- Manteca 115 kV and Schulte-Lammers 115 kV. The area limitation is thermal overload of the Tesla-Tracy 115 kV line above its emergency rating. This limiting contingency establishes a local capacity need of 319 MW (includes 27 MW of deficiency) in 2023.

The single most critical contingency for the Tesla-Bellota pocket is the loss of Tesla- Schulte #2 115 kV line and the loss of the GWF Tracy unit #3. The area limitation is thermal overload of the Tesla-Schulte #1 115 kV line. This single contingency establishes a local capacity need of 201 MW in 2023.

All of the resources needed to meet the Stanislaus sub-area count towards the Tesla- Bellota sub-area LCR need.

Effectiveness factors: All units within this sub-area are needed therefore no effectiveness factor is required.

Lockeford Sub-area The critical contingency for the Lockeford area is the loss of Lockeford-Industrial 60 kV circuit and Lockeford-Lodi #2 60 kV circuit. The area limitation is thermal overloading of the Lockeford-Lodi #3 60 kV circuit. This limiting contingency establishes a local capacity need of 103 MW (including 79 MW of deficiency) in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

The most critical single contingency is the loss of the Lockeford-Industrial 60 kV line with Lodi CT unit out of service. The area limitation is thermal overloading of the Lockeford-Lodi 60 kV line and establishes a local capacity need of 44 MW (including 20 MW of deficiency) in 2023.

Effectiveness factors: All units within this sub-area are needed therefore no effectiveness factor is required.

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Weber Sub-area The critical contingency is the loss of Stockton A-Weber #1 & #2 60 kV lines. The area limitation is thermal overloading of the Stockton A-Weber #3 60 kV line. This limiting contingency establishes a local capacity need of 17 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Stockton Overall The requirement for this area is driven by the sum of requirements for the Tesla-Bellota, Lockeford and Weber sub-areas.

Changes compared to last year’s results: The 2023 load forecast went up by 192 MW and the overall LCR has decreased by 263 MW compared to the 2022 due to transmission project implementation.

Stockton Overall Requirements: 2023 QF Muni Market Max. Qualifying (MW) (MW) (MW) Capacity (MW) Available generation 18 126 540 684

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single)11 225 20 245 Category C (Multiple)12 333 106 439

11 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 12 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

97 / 226 5. Greater Bay Area

Area Definition:

The transmission tie lines into the Greater Bay Area are: 1) Lakeville-Sobrante 230 kV 2) Ignacio-Sobrante 230 kV 3) Parkway-Moraga 230 kV 4) Bahia-Moraga 230 kV 5) Lambie SW Sta-Vaca Dixon 230 kV 6) Peabody-Contra Costa P.P. 230 kV 7) Tesla-Kelso 230 kV 8) Tesla-Delta Switching Yard 230 kV 9) Tesla-Pittsburg #1 230 kV 10) Tesla-Pittsburg #2 230 kV 11) Tesla-Newark #1 230 kV 12) Tesla-Newark #2 230 kV 13) Tesla-Ravenswood 230 kV 14) Tesla-Metcalf 500 kV 15) Moss Landing-Metcalf 500 kV 16) Moss Landing-Metcalf #1 230 kV 17) Moss Landing-Metcalf #2 230 kV 18) Oakdale TID-Newark #1 115 kV 19) Oakdale TID-Newark #2 115 kV The substations that delineate the Greater Bay Area are: 1) Lakeville is out Sobrante is in 2) Ignacio is out Sobrante is in 3) Parkway is out Moraga is in 4) Bahia is out Moraga is in 5) Lambie SW Sta is in Vaca Dixon is out 6) Peabody is out Contra Costa P.P. is in 7) Tesla is out Kelso is in 8) Tesla is out Delta Switching Yard is in 9) Tesla is out Pittsburg is in 10) Tesla is out Pittsburg is in 11) Tesla is out Newark is in 12) Tesla is out Newark is in 13) Tesla is out Ravenswood is in 14) Tesla is out Metcalf is in 15) Moss Landing is out Metcalf is in 16) Moss Landing is out Metcalf is in 17) Moss Landing is out Metcalf is in 18) Oakdale TID is out Newark is in 19) Oakdale TID is out Newark is in

98 / 226 Load:

Total 2023 busload within the defined area: 10,502 MW with -465 MW of AAEE, -61 MW of Behind the meter DG, 245 MW of losses and 220 MW of pumps resulting in total load + losses + pumps of 10,441 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Oakland Clean Energy Initiative Project (Oakland CTs are assumed retired) 2. Morgan Hill Area Reinforcement (revised scope) 3. Metcalf-Piercy & Swift and Newark-Dixon Landing 115 kV Upgrade 4. East Shore-Oakland J 115 kV Reconductoring Project 5. Vaca Dixon-Lakeville 230 kV Corridor Series Compensation 6. Metcalf-Evergreen 115 kV Line Reconductoring

Critical Contingency Analysis Summary:

Oakland Sub-area No requirement.

Llagas Sub-area The most critical contingency is an outage of Metcalf D-Morgan Hill 115 kV line with the Morgan Hill-Green Valley 115 kV line. The area limitation is the thermal overloading of the Morgan Hill-Llagas 115 kV line above its emergency rating. This limiting contingency establishes a local capacity need of 13 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

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San Jose Sub-area The most critical contingency is the Newark-Los Esteros 230 kV line overlapped with Metcalf-Los Esteros 230 kV line. The limiting element is the Newark-NRS 115 kV line and establishes a local capacity 293 MW in 2023 as minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: See Appendix B – Table titled San Jose. For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7320 (T-133Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

South Bay-Moss Landing Sub-area The most critical contingency is an outage of the Tesla-Metcalf 500 kV and Moss Landing-Los Banos 500 kV. The area limitation is thermal overloading of the Las Aguillas-Moss Landing 230 kV. This limiting contingency establishes a LCR of 1977 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Resources in San Jose and Llagas sub-areas are also included in this sub-area.

Effectiveness factors: See Appendix B – Table titled South Bay-Moss Landing.

Ames/Pittsburg/Oakland Sub-areas Combined The one critical contingency in NCNB and two most critical contingencies in Ames/Pittsburg/Oakland listed below together establish a local capacity need of 2430 MW in 2023 as follows: 553 MW in NCNB and 1630 MW in the Ames/Pittsburg/Oakland as the minimum capacity necessary for reliable load serving capability within these sub-areas.

100 / 226 The most critical contingencies in the Bay Area are: 1) an outage of DCTL Newark-Ravenswood & Tesla-Ravenswood 230 kV with limitation of thermal overloading of Ames-Ravenswood #1 115 kV line. And 2) an overlapping outage of Moraga-Sobrante & Moraga-Claremont #1 115 kV lines with limitation of thermal overloading of Moraga-Claremont #2 115 kV line.

The most critical contingency in North Coast/North Bay area is an outage of Vaca Dixon-Tulucay 230 kV line with Delta Energy Center power plant out of service. The area limitation is thermal overloading of Vaca Dixon-Lakeville 230 kV line.

Effectiveness factors: See Appendix B – Table titled Ames/Pittsburg/Oakland. For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7320 (T-133Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Contra Costa Sub-area The most critical contingency is an outage of Kelso-Tesla 230 kV with Gateway out of service. The area limitation is thermal overloading of the Delta Switching Yard-Tesla 230 kV line. This limiting contingency establishes a LCR of 1145 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: For most helpful procurement information please read procedure 2210Z Effectiveness Factors under 7320 (T-133Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Bay Area overall The most critical need is the aggregate of sub-area requirements. This establishes a LCR of 4752 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this area.

101 / 226 The most critical single contingency is the loss of the Tesla-Metcalf 500 kV with Delta Energy Center out of service. The area limitation is reactive margin. This limiting contingency establishes a local capacity need of 3676 MW in 2023 .

Effectiveness factors: For most helpful procurement information please read procedure 2210Z Effectiveness Factors under 7320 (T-133Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Changes compared to last year’s results: From 2022 the load forecast increased by 261 MW compared with the physically defined Bay Area. The LCR has decreased by 563 MW due to new transmission projects.

Bay Area Overall Requirements: 2023 Wind QF/Selfgen Muni Market Battery Max. Qualifying (MW) (MW) (MW) (MW) (MW) Capacity (MW) Available generation 321 245 382 6102 4 7054

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single)13 3676 0 3676 Category C (Multiple)14 4752 0 4752

13 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 14 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

102 / 226 6. Greater Fresno Area

Area Definition:

The transmission facilities coming into the Greater Fresno area are: 1) Gates-Mustang #1 230 kV 2) Gates-Mustang #2 230 kV 3) Gates #5 230/70 kV Transformer Bank 4) Mercy Spring 230 /70 Bank # 1 5) Los Banos #3 230/70 Transformer Bank 6) Los Banos #4 230/70 Transformer Bank 7) Warnerville-Wilson 230kV 8) Melones-North Merced 230 kV line 9) Panoche-Tranquility #1 230 kV 10) Panoche-Tranquility #2 230 kV 11) Panoche #1 230/115 kV Transformer Bank 12) Panoche #2 230/115 kV Transformer Bank 13) Corcoran-Smyrna 115kV 14) Coalinga #1-San Miguel 70 kV The substations that delineate the Greater Fresno area are: 1) Gates is out Mustang is in 2) Gates is out Mustang is in 3) Gates 230 is out Gates 70 is in 4) Mercy Springs 230 is out Mercy Springs 70 is in 5) Los Banos 230 is out Los Banos 70 is in 6) Los Banos 230 is out Los Banos 70 is in 7) Warnerville is out Wilson is in 8) Melones is out North Merced is in 9) Panoche is out Tranquility #1 is in 10) Panoche is out Tranquility #2 is in 11) Panoche 230 is out Panoche 115 is in 12) Panoche 230 is out Panoche 115 is in 13) Corcoran is in Smyrna is out 14) Coalinga is in San Miguel is out

Load:

Total 2023 load within the defined area: 3276 MW with -114 MW of AAEE, 104 MW of losses and -35 MW of DG resulting in total load + losses of 3231 MW.

List of physical units: See Appendix A.

103 / 226 Major new projects modeled: 1. Gates #12 500/230 Transformer Bank addition (Dec 2019) 2. Wilson 115 kV SVC(2020) 3. Northern Fresno 115 kV Reinforcement (Revised scope- 2020) 4. Wilson-Legrand 115 kV Reconductoring (2020) 5. Panoche-Oro Loma 115 kV Reconductoring (2020) 6. Oro Loma 70 kV Reinforcement (2020) 7. Reedley 70 kV Reinforcement Projects (2021) 8. Herndon-Bullard Reconductoring Projects (2021)

Critical Contingency Analysis Summary:

Hanford Sub-area The most critical contingency for the Hanford sub-area is the loss of the Gates-Mustang #1 and #2 230 kV lines, which would thermally overload the McCall-Kingsburg #1 115 kV line . This limiting contingency establishes a local capacity need of 107 MW in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Coalinga Sub-area The most critical contingency for the Coalinga sub-area is the loss of the Gates #5 230/70 kV transformer followed by the Panoche-Schindler #1 and #2 common tower contingency, which could cause voltage instability in the pocket. This limiting contingency establishes a local capacity need of 16 MW in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

104 / 226 Borden Sub-area The most critical contingency for the Borden sub-area is the loss of the Borden #4 230/70 kV transformer followed by the Friant-Coppermine 70 kV line, which could cause overload on the Borden #1 230/70 kV transformer. This limiting contingency establishes a local capacity need of 8 MW in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Reedley Sub-area The most critical contingency for the Reedley sub-area is the loss of the McCall- Reedley (McCall-Wahtoke) 115 kV line followed by the Sanger-Reedley 115 kV line, which could thermally overload the Kings River-Sanger-Reedley (Sanger-Rainbow Tap) 115 kV line. This limiting contingency establishes a local capacity need of 12 MW (including 1 MW of deficiency) in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

There is no single critical contingency in this sub-area.

Herndon Sub-area The most critical contingency is the loss of Herndon-Woodward 115kV line and Herndon-Barton115kV line. This contingency could thermally overload the Herndon- Manchester 115 kV line. This limiting contingency established an LCR of 821 MW in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

The single most critical contingency is the loss of Herndon-Barton 115 kV line with Balch 1 generating unit out of service. This contingency would thermally overload the Herndon-Manchester 115 kV line and establishes an LCR of 293 MW.

105 / 226 Effectiveness factors: See Appendix B - Table titled Herndon. For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7430 (T-129) posted at: http://www.caiso.com/Documents/2210Z.pdf

Overall (Wilson) Sub-area The most critical contingency for the Fresno area is the loss of the Gates-Mustang 230 kV line #1 or #2 and Helms-Gregg 230 kV line, which could thermally overload the remaining Gates-Mustang 230 kV line. This limiting contingency establishes a local capacity need of 1688 MW in 2023 as the generation capacity necessary for reliable load serving capability within this area.

The most critical single contingency for the Fresno area is the loss of the Gates- Mustang 230kV line #1 or #2 and one Helms unit, which could thermally overload the remaining Gates-Mustang 230kV line. This limiting contingency establishes a local capacity need of 1688 MW.

Effectiveness factors: For most helpful procurement information please read procedure 2210Z Effectiveness Factors under 7430 (T-129) posted at: http://www.caiso.com/Documents/2210Z.pdf

Changes compared to last year’s results: Overall the load forecast decreased by 121 MW. The LCR need has decreased by 172 MW 2022 need due to load decrease, and new transmission projects.

Fresno Area Overall Requirements: 2023 QF/Selfgen Muni Market Max. Qualifying (MW) (MW) (MW) Capacity (MW) Available generation 28 312 3169 3509

106 / 226 2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single) 15 1688 0 1688 Category C (Multiple) 16 1688 0 1688

7. Kern Area

Area Definition: The transmission facilities coming into the Kern PP sub-area are: 1) Midway-Kern PP #1 230 kV Line 2) Midway-Kern PP #2 230 kV Line 3) Midway-Kern PP #3 230 kV Line 4) Midway-Kern PP #4 230 kV Line 5) Famoso-Lerdo 115 kV Line (Normal Open) 6) Wasco-Famoso 70 kV Line (Normal Open) 7) Copus-Old River 70 kV Line (Normal Open) 8) Copus-Old River 70 kV Line (Normal Open) 9) Weedpatch CB 32 70 kV (Normal Open) 10) Wheeler Ridge-Lamont 115 kV Line (Normal Open)

The substations that delineate the Kern-PP sub-area are: 1) Midway 230 kV is out and Bakerfield 230 kV is in 2) Midway 230 kV is out Kern PP 230 kV is in 3) Midway 230 kV is out and Stockdale 230 kV is in 4) Midway 230 kV is out Kern PP 230 kV is in 5) Famoso 115 kV is out Cawelo 115 kV is in 6) Wasco 70 kV is out Mc Farland 70 kV is in 7) Copus 70 kV is out, South Kern Solar 70 kV is in 8) Lakeview 70 kV is out, San Emidio Junction 70 kV is in 9) Weedpath 70 kV is out, Wellfield 70 kV is in 10) Wheeler Ridge 115 kV is out, Adobe Solar 115 kV is in

15 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 16 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

107 / 226 Load: 2023 total busload within the defined area is 1183 MW with -44 MW of AAEE, 10 MW of losses and -9 MW DG resulting in a total (load plus losses) of 1140 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Kern PP 230 kV area reinforcement project 2. Midway-Kern PP 1, 3 &4 230 kV line capacity increase project

Critical Contingency Analysis Summary

Westpark Sub-area The most critical contingency is PSE-Bear and Kern-Westpark # 1 or # 2 resulting in thermal overload of the remaining Kern-Westpark # 1 or # 2. This limiting contingency establishes a LCR of 51 MW (including 6 MW of deficiency) in 2019 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

Kern Oil Sub-area The most critical contingency is the Kern PP-Live Oak 115 kV Line and Kern PP-7th Standard 115 kV Line resulting in the thermal overload of the Kern PP-Magunden-Witco 115 kV Line (Kern PP-Kern Water section). This limiting contingency establishes a LCR of 131 MW (including 2 MW of deficiency) in 2019 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

The most critical single contingency is the loss of the Kern PP -7th Standard 115 kV line with Mount Poso unit out of service. The area limitation is thermal overloading of the Kern PP-Magunden-Witco 115 kV line (Kern PP-Kern Water section) and establishes a local capacity need of 107 MW in 2023.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

108 / 226 For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7450 (New) posted at: http://www.caiso.com/Documents/2210Z.pdf

South Kern PP Sub-area South Kern PP Sub-area has been greatly reduced due to Kern PP 230 kV area reinforcement and the Midway-Kern 1, 3 & 4 230 kV line capacity increase transmission projects. For 2023 this sub-area need is lower than the Wespark and Kern Oil sub-areas combined.

Changes compared to last year’s results: Kern area load has gone up by 255 MW due to definition change, with no impact to local area designation for any resources. Comparing the same definition as last year, the Kern area load forecast has gone down by 9 MW. The LCR requirement has increased by 59 MW mainly due to the needs in the Westpark sub-area which has no requirement in the 2022 study.

Kern Area Overall Requirements: 2023 QF/Selfgen Market Max. Qualifying (MW) (MW) Capacity (MW) Available generation 13 462 475

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single) 17 152 6 158 Category C (Multiple) 18 174 8 182

17 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 18 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

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8. LA Basin Area

Area Definition:

The transmission tie lines into the LA Basin Area are: 1) San Onofre - San Luis Rey #1, #2, and #3 230 kV Lines 2) San Onofre - Talega #2 230 kV Lines 3) San Onofre - Capistrano #1 230 kV Lines 4) Lugo - Mira Loma #2 & #3 500 kV Lines 5) Lugo - Rancho Vista #1 500 kV Line 6) Vincent – Mesa 500 kV Line 7) Sylmar - Eagle Rock 230 kV Line 8) Sylmar - Gould 230 kV Line 9) Vincent - Mesa #1 & #2 230 kV Lines 10) Vincent - Rio Hondo #1 & #2 230 kV Lines 11) Devers - Red Bluff 500 kV #1 and #2 Lines 12) Mirage – Coachela Valley # 1 230 kV Line 13) Mirage - Ramon # 1 230 kV Line 14) Mirage - Julian Hinds 230 kV Line The substations that delineate the LA Basin Area are: 1) San Onofre is in San Luis Rey is out 2) San Onofre is in Talega is out 3) San Onofre is in Capistrano is out 4) Mira Loma is in Lugo is out 5) Rancho Vista is in Lugo is out 6) Eagle Rock is in Sylmar is out 7) Gould is in Sylmar is out 8) Mira Loma is in Vincent is out 9) Mesa is in Vincent is out 10) Rio Hondo is in Vincent is out 11) Devers is in Red Bluff is out 12) Mirage is in Coachela Valley is out 13) Mirage is in Ramon is out 14) Mirage is in Julian Hinds is out

110 / 226 Load:

The CEC-adopted demand forecast for 2023 from the 2018-2030 Mid Baseline, Low AAEE and AAPV savings for 1-in-10 heat wave forecast is 20,076 MW19. A total of 20,072 MW20 of managed 1-in-10 peak demand was modeled for the study.

List of physical units: See Appendix A.

Major new projects modeled: 1. Mesa Loop-In Project and Laguna Bell Corridor 230 kV line upgrades 2. Delaney – Colorado River 500 kV Line 3. Hassayampa – North Gila #2 500 kV Line (APS) 4. West of Devers 230 kV line upgrades 5. Full implementation of the CPUC-approved long-term procurement plan (LTPP) for 431 MW of preferred resources in the western LA Basin sub-area 6. Alamitos repowering (640 MW, Non-OTC) 7. Retirement of 2,010 MW of the existing Alamitos once-through-cool generation 8. Huntington Beach repowering (644 MW, Non-OTC) Retirement of 452 MW of the existing Huntington Beach once-through-cool generation

Critical Contingency Analysis Summary

El Nido Sub-area: The most critical contingency for the El Nido sub-area is the loss of the La Fresa – Hinson 230 kV line followed by the loss of the La Fresa – Redondo #1 and #2 230 kV lines, which could cause voltage collapse. This limiting contingency establishes an LCR of 53 MW (including 12.5 MW are existing 20-minute demand response and 23.7 MW of LTPP preferred resources) in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

19 https://efiling.energy.ca.gov/GetDocument.aspx?tn=222579 (Form 1.5d) 20 This load represents the geographic LA Basin load which includes Saugus Substation load. The geographic LA Basin load matches with the the CEC’s forecast for the LA Basin.

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Effectiveness factors: All units have the same effectiveness factor.

Western LA Basin Sub-area: The most limiting contingency is the loss of Mesa – Redondo 230 kV line, system readjusted, followed by the loss of Mesa – Lighthipe 230 kV line or vice versa, which could result in thermal overload of the Mesa – Laguna Bell #1 230 kV line. This limiting contingency establishes a local capacity need of 3,970 MW (including 162 MW are of existing 20-minute demand response and 432 MW of the LTPP preferred resources) in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: See Appendix B - Table titled LA Basin. For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7630 (G-219Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

There are other combinations of contingencies in the area that could overload a significant number of 230 kV lines in this sub-area have less LCR need. As such, anyone of them (combination of contingencies) could become binding for any given set of procured resources. As a result, these effectiveness factors may not be the best indicator towards informed procurement.

West of Devers Sub-area: There are no local capacity requirements due to implementation of the Mesa Loop-in as well as West of Devers reconductoring projects.

Valley-Devers Sub-area: There are no local capacity requirements due to implementation of the Colorado River- Delaney 500 kV line project.

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Valley Sub-area: There are no local capacity requirements due to implementation of the Colorado River- Delaney 500 kV line project.

Eastern LA Basin Sub-area: The most critical contingency is the loss of the Alberhill - Serrano 500 kV line, followed by an N-2 of Red Bluff-Devers #1 and #2 500 kV lines, which could result in voltage instability. This limiting contingency establishes a local capacity need of 2,702 MW (including 159 MW of existing 20-minute demand response) in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this area have the same effectiveness factor.

Overall LA Basin Area and San Diego-Imperial Valley Area Combined: The LCR needs of the LA Basin area and San Diego-Imperial Valley area have been considered through a coordinated study process to ensure that the resource needs for each LCR area not only satisfy its own area reliability need but also provide support to the other area if needed. With the retirement of the San Onofre Nuclear Generating Station, and the impending retirement of other once-through cooled generation in the LA Basin and San Diego areas, the two areas are electrically interdependent on each other. Resource needs in one area are dependent on the amount of resources that are dispatched for the adjacent area and vice versa. The SDG&E system, being the southernmost electrical area in the ISO’s southern system and smaller of the overall LA Basin-San Diego-Imperial Valley area, is evaluated first for its LCR needs. The LCR needs for the LA Basin and its subareas are then evaluated after the initial determination of the LCR needs for the overall San Diego-Imperial Valley area. The LCR needs in the overall San Diego-Imperial Valley area are then re-checked to ensure that the initial determination is still adequate. This iterative process is needed due to the interaction of resources on the LCR needs in the LA Basin-San Diego-Imperial Valley area. With this process, the LCR needs for the respective areas are coordinated within

113 / 226 the overall LA Basin-San Diego-Imperial Valley area. It is important to note that the San Diego subarea is a part or subset of the overall San Diego-Imperial Valley area. The total LCR needs for the combined LA Basin-San Diego-Imperial Valley area are the sum of the LCR needs for the LA Basin and the San Diego-Imperial Valley area.

As part of the load assumptions for the 2023 LCR study, the ISO utilized the 1-in-2 hourly load forecast from the California Energy Commission (CEC) and adjusted to the 1-in-10 demand forecast for the peak day for 2023 timeframe utilizing the multiplier from the CEC to determine the percentage for scaling the loads for SDG&E and SCE for simultaneous peak at the time of SCE and SDG&E peak loads, respectively. Two study cases were developed: one with SCE peak load and corresponding SDG&E simultaneous load at SCE peak; the other had SDG&E peak load with corresponding SCE simultaneous load. This is to capture better load models between the two areas of SCE and SDG&E at each other’s peak demand. In previous year’s LCR study, the ISO modeled both the LA Basin and SDG&E at their peak demands simultaneously based on historical load data that showed loads in these two areas that peaked at the same time. The new approach is based on the forecast of hourly loads in the future from the CEC. The following two diagrams illustrate the hourly consumption loads and the managed loads for SCE and SDG&E on the CEC’s forecast peak day for these two areas on August 31, 2023. The following table illustrates the estimated derates for either SCE or SDG&E loads at the time of SDG&E or SCE peak demand, respectively.

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115 / 226 SCE peak demand SDG&E @ SCE peak demand SDG&E peak demand SCE @ SDG&E peak demand

Hourly Hourly LSE/BA LSE/BA Hourly Managed Hourly Managed Table Table Managed Peak Managed % of own Peak % of own Date/time peak Date/time Date/time peak Date/time Demand Year Demand Demand peak Demand peak (PDT)* demand (PDT)* (PDT)* demand (PDT)* from (MW) (MW) demand (MW) demand forecast forecast plot from from plot from (MW)** (MW)** (MW) plot plot

8/31/2023 8/31/2023 8/31/2023 8/31/2023 2023 25,359 25,368 4,400 96.30% 4,569 4,554 23,548 92.86% 17:00 hr. 17:00 hr. 20:00 hr. 20:00 hr.

Notes: *All hour expressed in PDT hour ending (HE)

**Peak demand from the CEC posted 2017 CED Revised Forecast for LSE/BA Table for Mid Demand Level (1-in-10) with Low AAEE and AAPV

The following is the discussion of the LCR needs for each of these respective areas:

1. Overall San Diego-Imperial Valley Area:

The most critical contingency resulting in thermal loading concerns for the overall San Diego-Imperial Valley area is the G-1/N-1 (Category B) overlapping outage that involves the loss of the TDM combined cycled power plant (593 MW), system readjustment, followed by the loss of the Imperial Valley – North Gila 500 kV line or vice versa (Category C). This overlapping contingency could thermally overload the El Centro 230/92 kV transformer, which is owned by the Imperial Irrigation District (IID). For the 2023 LCR study, the Imperial Valley – El Centro (i.e., the “S” line) line upgrades are implemented with an estimated in-service date by the end of 2021. Furthermore the El Centro 230/161 kV transformer would be the next limiting constraint if the El Centro 230/92 kV constraint is removed. The aforementioned contingency establishes a total local capacity need of 4,132 MW in 2023 as the local resource capacity necessary for reliable load serving capability within the overall San Diego – Imperial Valley area.

116 / 226 2. Overall LA Basin Area:

The most critical contingency resulting in thermal loading concern for the overall LA Basin is the G-1/N-1 contingency of TDM power plant (593 MW), system readjustment, followed by the loss of the Imperial Valley – North Gila 500 kV line or vice versa. This overlapping contingency could thermally overload the IID’s El Centro 230/92 kV transformer. This establishes a total local capacity need of 6,793 MW (including 321 MW of existing 20-minute demand response as well as 432 MW of LTPP preferred resources) in the LA Basin area in 2023 as the minimum resource capacity necessary for reliable load serving capability within this area.

The overall local capacity need for the combined LA Basin-San Diego-Imperial Valley area is 10,925 MW in 2023 time frame as follows: 6,793 MW in the overall LA Basin and 4,132 MW in the overall San Diego-Imperial Valley area as the minimum capacity necessary for reliable load serving capability within these areas. The most limiting constraint is the thermal loading concern on the IID-owned El Centro 230/92 kV transformer under an overlapping G-1/N-1 (or vice versa) contingency, followed closely the limiting constraint on the Mesa – Laguna Bell 230 kV line under an overlapping N- 1/N-1 contingency of the Mesa – Redondo 230kV line, system readjustment, then followed by the Mesa – Lighthipe 230kV line.

Effectiveness factors: See Appendix B - Table titled LA Basin. For other helpful procurement information please read procedure 2210Z Effectiveness Factors under 7570 (T-144Z), 7580 (T-139Z), 7590 (T-137Z, 6750) and 7680 (T-130Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Changes compared to last year’s results: Compared with 2022, the load forecast is higher by 1052 MW and the LCR need has increaed by 771 MW, primarily due to higher demand forecast.

117 / 226 LA Basin Overall Requirements: QF Muni Wind Market Preferred 20 Min. Mothball Max. Qualifying 2023 (MW) (MW) (MW) (MW) Res. (MW) DR (MW) (MW) Capacity (MW) Available 279 1,164 124 5,556 432 321 435 8,311 generation

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single)21 6,793 0 6,793 Category C (Multiple)22 6,793 0 6,793

9. Big Creek/Ventura Area

Area Definition:

The transmission tie lines into the Big Creek/Ventura Area are: 1) Antelope #1 500/230 kV Transformer 2) Antelope #2 500/230 kV Transformer 3) Sylmar - Pardee 230 kV #1 and #2 Lines 4) Vincent - Pardee 230 kV #2 Line 5) Vincent - Santa Clara 230 kV Line The substations that delineate the Big Creek/Ventura Area are: 1) Antelope 500 kV is out Antelope 230 kV is in 2) Antelope 500 kV is out Antelope 230 kV is in 3) Sylmar is out Pardee is in 4) Vincent is out Pardee is in 5) Vincent is out Santa Clara is in

21 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 22 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

118 / 226 Load:

Total 2023 busload within the defined area23 is 4708 MW including the impact of AAEE and AAPV based on the CEC managed forecast with 82 MW of losses and 379 MW of pumps resulting in a total managed load + losses + pumps of 5169 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Big Creek Corridor Rating Increase Project (ISD - 12/31/2018). 2. Pardee-Moorpark No. 4 230 kV Transmission Circuit (ISD – 12/31/2020)

Critical Contingency Analysis Summary:

Rector Sub-area: LCR need is satisfied by the need in the larger Vestal sub-area.

Effectiveness factors: See Appendix B - Table titled Rector.

Vestal Sub-area: The most critical contingencies for the Vestal sub-area are: 1. Loss of one of the Magunden-Vestal 230 kV lines with the Eastwood unit out of service, which would thermally overload the remaining Magunden-Vestal 230 kV line and 2. Loss of Magunden-Springville #1 230 kV line with Eastwood out of service which would thermally overload the Magunden-Springville #2 230 kV line.

These limiting contingencies establish a LCR of 621 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

23 The Big Creek Ventura LCA includes the Saugus Substation.

119 / 226 Effectiveness factors: For helpful procurement information please read procedure 2210Z Effectiveness Factors under 7500 posted at: http://www.caiso.com/Documents/2210Z.pdf

Santa Clara Sub-area: The most critical contingency is the loss of the Pardee - Santa Clara 230 kV line followed by the loss of Moorpark - Santa Clara 230 kV #1 and #2 lines, which would cause voltage collapse. This limiting contingency establishes a local capacity need of 295 MW (including 102 MW of deficiency) in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: The value of the local capacity need varies depending on the location and reactive power capability provided to the transmission system by the new resource or resources that will be procured to fill the need.

Reactive power capability of new resource(s) Location of new resource(s) 0.95 lead/lag power Unity power factor factor range Goleta 66 kV 295 MW 316 MW Santa Clara 66 kV 322 MW 358 MW

Moorpark Sub-area: No requirement identified.

Big Creek/Ventura overall: The most critical contingency is the loss of the Lugo - Victorville 500 kV line followed by loss of one of the Sylmar - Pardee 230 kV line, which would thermally overload the remaining Sylmar - Pardee 230 kV line. This limiting contingency establishes a local capacity need of 2,690 MW as the minimum capacity necessary for reliable load serving capability within this area.

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The single most critical contingency is the loss of Sylmar - Pardee #1 (or # 2) line with Pastoria power plant (CCGT) out of service, which could thermally overload the remaining Sylmar - Pardee #2 or #1 230 kV line. This limiting contingency establishes a local capacity need of 2,212 MW.

Effectiveness factors: For helpful procurement information please read procedure 2210Z Effectiveness Factors under 7680 (T-130Z), 7510 (T-163Z), 7550 (T-159Z) and 8610 (T-131Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

Changes compared to last year’s results: Compared with 2022 the load forecast is up by 149 MW and the LCR need has increased by 195 MW due to load forecast increase as well as deficiency increase resulting from resource retirements.

Big Creek/Ventura Overall Requirements: 2023 QF Muni Preferred Market Max. Qualifying (MW) (MW) Res. (MW) (MW) Capacity (MW) Available generation 52 372 108 2975 3507

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) Requirement Category B (Single)24 2212 0 2212 Category C (Multiple)25 2690 102 2792

24 LCR requirement for a single contingency means that there wouldn’t be any criteria violations following the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 25 LCR requirement for multiple contingencies means that not only there wouldn’t be any criteria violations following the loss of a single element, but also the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

121 / 226 10. San Diego-Imperial Valley Area

Area Definition:

The transmission tie lines forming a boundary around the Greater San Diego-Imperial Valley area include: 1) Imperial Valley – North Gila 500 kV Line 2) Otay Mesa – Tijuana 230 kV Line 3) San Onofre - San Luis Rey #1 230 kV Line 4) San Onofre - San Luis Rey #2 230 kV Line 5) San Onofre - San Luis Rey #3 230 kV Line 6) San Onofre – Talega 230 kV Line 7) San Onofre – Capistrano 230 kV Line 8) Imperial Valley – El Centro 230 kV Line 9) Imperial Valley – La Rosita 230 kV Line The substations that delineate the Greater San Diego-Imperial Valley area are: 1) Imperial Valley is in North Gila is out 2) Otay Mesa is in Tijuana is out 3) San Onofre is out San Luis Rey is in 4) San Onofre is out San Luis Rey is in 5) San Onofre is out San Luis Rey is in 6) San Onofre is out Talega is in 7) San Onofre is out Capistrano is in 8) Imperial Valley is in El Centro is out 9) Imperial Valley is in La Rosita is out

Load:

The CEC-adopted demand forecast for 2023 from the 2018-2030 Mid Demand Baseline, Low AAEE and AAPV savings for 1-in-10 heat wave forecast is 4,554 MW. The total managed peak demand including 115 MW transmission losses modeled in the study is 4,535 MW.

List of physical units: See Appendix A.

Major new projects modeled: 1. Ocean Ranch 69 kV substation 2. Mesa Height TL600 Loop-in 3. Re-conductor of Mission-Mesa Heights 69 kV

122 / 226 4. Re-conductor of Kearny-Mission 69 kV line 5. TL6906 Mesa Rim rearrangement 6. Upgrade Bernardo - Rancho Carmel 69 kV line 7. Re-conductor of Japanese Mesa–Basilone–Talega Tap 69 kV lines 8. 2nd Miguel–Bay Boulevard 230 kV line 9. Sycamore–Penasquitos 230 kV line 10. 2nd Mission 230/69 kV bank 11. Suncrest SVC project 12. By-passing 500 kV series capacitor banks on the Southwest Powerlink and Sunrise Powerlink lines 13. Encina generation retirement 14. Carlsbad Energy Center (5x100 MW) 15. Battery energy storage projects (total of 78 MW) at various locations: El Cajon (8 MW), Escondido (30 MW), Melrose (2x20 MW) 16. TL632 Granite loop-in and TL6914 reconfiguration 17. 2nd San Marcos–Escondido 69 kV line 18. Reconductor of Stuart Tap–Las Pulgas 69 kV line (TL690E) 19. 2nd Poway–Pomerado 69 kV line 20. Artesian 230 kV expansion with 69 kV upgrade 21. South Orange County Reliability Enhancement 22. Imperial Valley bank #80 replacement

Critical Contingency Analysis Summary:

El Cajon Sub-area The most critical contingency for the El Cajon sub-area is the loss of the Granite - Los Coches 69 kV lines #1 and #2, which could thermally overload the El Cajon-Los Coches 69 kV line (TL631). This limiting contingency establishes a LCR of 35 MW in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area after the TL632 Granite Loop-In and TL6914 reconfiguration project are completed.

123 / 226 Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Mission Sub-area The LCR need for the Mission sub-area is eliminated with the completions of the T600 Clairemont – Kearny loop-in to Mesa Hights 69 kV and TL676 Mission – Mesa Heights 69 kV reconductor projects.

Esco Sub-area The most critical contingency for the Esco sub-area is the loss of anyone of the two Sycamore-Pomerado 69 kV lines (TL6915 or TL6924) followed by the loss of Artisian 230/69 kV transformer bank, which could thermally overload the remaining Sycamore- Pomerado 69 kV line. This limiting contingency establishes a LCR of 20 MW in 2023 as the minimum generation capacity necessary for reliable load serving capability within this sub-area.

Pala Sub-area The most critical contingency for the Pala sub-area is the loss of Pendleton – San Luis Rey 69kV line (TL6912) followed by the loss of Lilac - Pala 69kV line (TL6932), which could thermally overload the Monserate – Morro Hill Tap 69 kV line (TL694). This limiting contingency establishes a local capacity need of 10 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Border Sub-area The most critical contingency for the Border sub-area is the loss of Bay Boulevard – Otay 69kV line #1 (TL645) followed by Bay Boulevard Otay – 69 kV line #2 (TL646), which could thermally overload the Imperial Beach – Bay Boulevard 69 kV line (TL647).

124 / 226 This limiting contingency establishes a local capacity need of 108 MW in 2023 as the minimum capacity necessary for reliable load serving capability within this sub-area.

Effectiveness factors: All units within this sub-area have the same effectiveness factor.

Miramar Sub-area With the completions of the Sycamore - Penasquitos 230 kV line and second Miguel – Bay Boulevard 230 kV line projects, this sub-area is eliminated.

125 / 226 As part of the load assumptions for the 2023 LCR study, the ISO utilized the 1-in-2 hourly load forecast from the California Energy Commission (CEC) and adjusted to the 1-in-10 demand forecast for the peak day for 2023 timeframe utilizing the multiplier from the CEC to determine the percentage for scaling the loads for SDG&E and SCE for simultaneous peak at the time of SCE and SDG&E peak loads, respectively. Two study cases were developed: one with SCE peak load and corresponding SDG&E simultaneous load at SCE peak; the other had SDG&E peak load with corresponding SCE simultaneous load. This is to capture better load models between the two areas of SCE and SDG&E at each other’s peak demand. In previous year’s LCR study, the ISO modeled both the LA Basin and SDG&E at their peak demands simultaneously based on historical load data that showed loads in these two areas that peaked at the same time. The new approach is based on the forecast of hourly loads in the future from the CEC. The following two diagrams illustrate the hourly consumption loads and the managed loads for SCE and SDG&E on the CEC’s forecast peak day for these two areas on August 31, 2023. The following table illustrates the estimated derates for either SCE or SDG&E loads at the time of SDG&E or SCE peak demand, respectively.

126 / 226

SCE peak demand SDG&E @ SCE peak demand SDG&E peak demand SCE @ SDG&E peak demand

8/31/2023 8/31/2023 8/31/2023 8/31/2023 2023 25,359 25,368 4,400 96.30% 4,569 4,554 23,548 92.86% 17:00 hr. 17:00 hr. 20:00 hr. 20:00 hr.

Notes:

*All hour expressed in PDT hour ending (HE)

**Peak demand from the CEC posted 2017 CED Revised Forecast for LSE/BA Table for Mid Demand

127 / 226 Level (1-in-10) with Low AAEE and AAPV

The following is the discussion of the LCR needs for each of these respective areas:

1. Overall San Diego-Imperial Valley Area:

The most critical contingency resulting in thermal loading concerns for the overall San Diego-Imperial Valley area is the G-1/N-1 (Category B) overlapping outage that involves the loss of the TDM combined cycled power plant (593 MW), system readjustment, followed by the loss of the Imperial Valley – North Gila 500 kV line or vice versa (Category C). This overlapping contingency could thermally overload the Imperial Valley- El Centro 230/92 kV transformer26. This contingency establishes a total local capacity need of 4,132 MW in 2023 as the resource capacity necessary for reliable load serving capability within the overall San Diego – Imperial Valley area. This amount of LCR need was achieved after utilization of 20-minute demand response and LTPP LCR preferred resources in the LA Basin.

The overall combined LA Basin-San Diego-Imperial Valley area has a total of 10,925 MW in 2023 time frame as follows: 6,793 MW for the overall LA Basin and 4,132 MW for the overall San Diego-Imperial Valley area as the minimum capacity necessary for reliable load serving capability within these areas. The most limiting constraint is the thermal loading concern on the IID-owned El Centro 230/92 kV transformer under an overlapping G-1/N-1 (or vice versa) contingency, followed closely the limiting constraint on the Mesa – Laguna Bell 230kV line under an overlapping N-1/N-1 contingency of the Mesa – Redondo 230kV line, system readjustment, then followed by the Mesa – Lighthipe 230kV line.

Effectiveness factors: See Appendix B - Table titled San Diego. For other helpful procurement information please read procedure 2210Z Effectiveness

26 The El Centro 230/92kV transformer is owned and operated by the Imperial Irrigation District (IID) that is in connected in series with the IID-owned “S” line which connects the IID electrical grid with the ISO BAA’s SDG&E-owned electrical grid.

128 / 226 Factors under 7820 (T-132Z) posted at: http://www.caiso.com/Documents/2210Z.pdf

2. San Diego Sub-area:

San Diego sub-area is part of the overall San Diego-Imperial Valley LCR area. The LCR need for the San Diego sub-area can either be caused by the larger need for the San Diego-Imperial Valley area (as discussed in item #1 above), or be caused by other outages that exclusively affect the San Diego sub-area only. The ultimate San Diego sub-area LCR need will be determined by the larger requirement of these analyses.

For the outages that exclusively affect the San Diego sub-area only, it is the overlapping N-1-1 of the ECO-Miguel 500 kV line, system readjustment, followed by the outage of the Sycamore-Suncrest 230 kV line. The limiting constraint is the thermal loading concern on the remaining Sycamore-Suncrest 230 kV line, causing an LCR need of 2,731 MW for the San Diego sub-area.

Net Qualifying Capacity at time of net peak demand

The expectation of the Resource Adequacy (RA) program is to provide resources “when needed and where needed” in order to ensure safe and reliable operation of the grid in real time. The current Qualifying Capacity (QC) rules of Local Regulatory Agencies (LRAs) – and correspondingly Net Qualifying Capacity rules of the ISO - have not fully adjusted to changes in real time conditions and more specifically the shift of load to later hours of the day (6, 7 or 8 p.m.). This misalignment between capacity determinations and peak demands on the transmission system may result in critical local resources not being available during the most stressed demand conditions (net peak). As the ISO is mandated to maintain local and system reliability at all hours of the day during the entire year, this misalignment increases the probability that other procurement, such as Capacity Procurement Mechanism (CPM) or Reliability Must Run (RMR), may be needed.

Changes compared to last year’s results: Compared with the 2022 LCR study results, the 2023 adjusted peak demand forecast is lower by 518 MW. The overall LCR need for the San Diego – Imperial Valley area has

129 / 226 decreased by 511 MW primarily due to lower managed peak demand forecast as well as implementation of the S-line upgrades between IID and SDG&E. The LCR need could have been lower if not for the decrease of net qualifying capacity for solar generation located in the most effective area.

San Diego-Imperial Valley Area Overall Requirements:

2023 QF Wind Market Battery 20 minute Max. Qualifying (MW) (MW) (MW) (MW) DR (MW) Capacity (MW) Available generation 106 185 4,099 78 19 4,487

2023 Existing Generation Deficiency Total MW Capacity Needed (MW) (MW) LCR Need Category B (Single)27 4,132 0 4,132 Category C (Multiple)28 4,132 0 4,132

11. Valley Electric Area

Valley Electric Association LCR area has been eliminated on the basis of the following:  No generation exists in this area  No category B issues were observed in this area  Category C and beyond – o No common-mode N-2 issues were observed o No issues were observed for category B outage followed by a common- mode N-2 outage o All the N-1-1 issues that were observed can either be mitigated by the existing UVLS or by an operating procedure

27 A single contingency means that the system will be able the survive the loss of a single element, however the operators will not have any means (other than load drop) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards. 28 Multiple contingencies means that the system will be able the survive the loss of a single element, and the operators will have enough generation (other operating procedures) in order to bring the system within a safe operating zone and get prepared for the next contingency as required by NERC transmission operations standards.

130 / 226 Appendix A - List of physical resources by PTO, local area and market ID

V. Appendix A – List of physical resources by PTO, local area and market ID

MKT/SCHED UNIT LCR AREA LCR SUB-AREA NQC CAISO PTO BUS # BUS NAME kV NQC RESOURCE ID ID NAME NAME Comments Tag PG&E ALMEGT_1_UNIT 1 38118 ALMDACT1 13.8 23.40 1 Bay Area Oakland MUNI PG&E ALMEGT_1_UNIT 2 38119 ALMDACT2 13.8 23.50 1 Bay Area Oakland MUNI PG&E BANKPP_2_NSPIN 38820 DELTA A 13.2 11.55 1 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38820 DELTA A 13.2 11.55 2 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38820 DELTA A 13.2 11.55 3 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38815 DELTA B 13.2 11.55 4 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38815 DELTA B 13.2 11.55 5 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38770 DELTA C 13.2 11.55 6 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38770 DELTA C 13.2 11.55 7 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38765 DELTA D 13.2 11.55 8 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38765 DELTA D 13.2 11.55 9 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38760 DELTA E 13.2 11.55 10 Bay Area Contra Costa Pumps MUNI PG&E BANKPP_2_NSPIN 38760 DELTA E 13.2 11.55 11 Bay Area Contra Costa Pumps MUNI PG&E BRDSLD_2_HIWIND 32172 HIGHWINDS 34.5 42.93 1 Bay Area Contra Costa Aug NQC Wind PG&E BRDSLD_2_MTZUM2 32179 MNTZUMA2 0.69 20.72 1 Bay Area Contra Costa Aug NQC Wind PG&E BRDSLD_2_MTZUMA 32188 HIGHWND3 0.69 9.75 1 Bay Area Contra Costa Aug NQC Wind PG&E BRDSLD_2_SHILO1 32176 SHILOH 34.5 39.75 1 Bay Area Contra Costa Aug NQC Wind PG&E BRDSLD_2_SHILO2 32177 SHILOH 2 34.5 39.75 1 Bay Area Contra Costa Aug NQC Wind PG&E BRDSLD_2_SHLO3A 32191 SHILOH3 0.58 27.16 1 Bay Area Contra Costa Aug NQC Wind PG&E BRDSLD_2_SHLO3B 32194 SHILOH4 0.58 26.50 1 Bay Area Contra Costa Aug NQC Wind San Jose, South PG&E CALPIN_1_AGNEW 35860 OLS-AGNE 9.11 28.00 1 Bay Area Aug NQC Market Bay-Moss Landing PG&E CAYTNO_2_VASCO 30531 0162-WD 230 4.30 FW Bay Area Contra Costa Aug NQC Market PG&E CLRMTK_1_QF 0.00 Bay Area Oakland Not modeled QF/Selfgen PG&E COCOPP_2_CTG1 33188 MARSHCT1 16.4 195.90 1 Bay Area Contra Costa Aug NQC Market PG&E COCOPP_2_CTG2 33188 MARSHCT2 16.4 195.40 2 Bay Area Contra Costa Aug NQC Market PG&E COCOPP_2_CTG3 33189 MARSHCT3 16.4 194.80 3 Bay Area Contra Costa Aug NQC Market PG&E COCOPP_2_CTG4 33189 MARSHCT4 16.4 197.55 4 Bay Area Contra Costa Aug NQC Market

131 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Not modeled PG&E COCOSB_6_SOLAR 0.00 Bay Area Contra Costa Market Energy Only PG&E CROKET_7_UNIT 32900 CRCKTCOG 18 231.08 1 Bay Area Pittsburg Aug NQC QF/Selfgen San Jose, South PG&E CSCCOG_1_UNIT 1 36859 Laf300 12 3.00 1 Bay Area MUNI Bay-Moss Landing San Jose, South PG&E CSCCOG_1_UNIT 1 36859 Laf300 12 3.00 2 Bay Area MUNI Bay-Moss Landing San Jose, South PG&E CSCGNR_1_UNIT 1 36858 Gia100 13.8 24.00 1 Bay Area MUNI Bay-Moss Landing San Jose, South PG&E CSCGNR_1_UNIT 2 36895 Gia200 13.8 24.00 2 Bay Area MUNI Bay-Moss Landing PG&E CUMBIA_1_SOLAR 33102 COLUMBIA 0.38 7.79 1 Bay Area Pittsburg Aug NQC Market PG&E DELTA_2_PL1X4 33108 DEC CTG1 18 181.13 1 Bay Area Pittsburg Aug NQC Market PG&E DELTA_2_PL1X4 33109 DEC CTG2 18 181.13 1 Bay Area Pittsburg Aug NQC Market PG&E DELTA_2_PL1X4 33110 DEC CTG3 18 181.13 1 Bay Area Pittsburg Aug NQC Market PG&E DELTA_2_PL1X4 33107 DEC STG1 24 269.60 1 Bay Area Pittsburg Aug NQC Market Not modeled PG&E DIXNLD_1_LNDFL 1.30 Bay Area Market Aug NQC San Jose, South PG&E DUANE_1_PL1X3 36865 DVRaST3 13.8 48.36 1 Bay Area MUNI Bay-Moss Landing San Jose, South PG&E DUANE_1_PL1X3 36863 DVRaGT1 13.8 49.72 1 Bay Area MUNI Bay-Moss Landing San Jose, South PG&E DUANE_1_PL1X3 36864 DVRbGT2 13.8 49.72 1 Bay Area MUNI Bay-Moss Landing PG&E GATWAY_2_PL1X3 33119 GATEWAY2 18 177.51 1 Bay Area Contra Costa Aug NQC Market PG&E GATWAY_2_PL1X3 33120 GATEWAY3 18 177.51 1 Bay Area Contra Costa Aug NQC Market PG&E GATWAY_2_PL1X3 33118 GATEWAY1 18 187.47 1 Bay Area Contra Costa Aug NQC Market Llagas, South PG&E GILROY_1_UNIT 35850 GLRY COG 13.8 69.00 1 Bay Area Aug NQC Market Bay-Moss Landing Llagas, South PG&E GILROY_1_UNIT 35850 GLRY COG 13.8 36.00 2 Bay Area Aug NQC Market Bay-Moss Landing Llagas, South PG&E GILRPP_1_PL1X2 35851 GROYPKR1 13.8 47.70 1 Bay Area Aug NQC Market Bay-Moss Landing Llagas, South PG&E GILRPP_1_PL1X2 35852 GROYPKR2 13.8 47.70 1 Bay Area Aug NQC Market Bay-Moss Landing Llagas, South PG&E GILRPP_1_PL3X4 35853 GROYPKR3 13.8 46.20 1 Bay Area Aug NQC Market Bay-Moss Landing PG&E GRZZLY_1_BERKLY 32741 HILLSIDE_12 12.5 24.57 1 Bay Area None Aug NQC Net Seller

132 / 226 Appendix A - List of physical resources by PTO, local area and market ID

PG&E KELSO_2_UNITS 33813 MARIPCT1 13.8 49.51 1 Bay Area Contra Costa Aug NQC Market PG&E KELSO_2_UNITS 33815 MARIPCT2 13.8 49.51 2 Bay Area Contra Costa Aug NQC Market PG&E KELSO_2_UNITS 33817 MARIPCT3 13.8 49.51 3 Bay Area Contra Costa Aug NQC Market PG&E KELSO_2_UNITS 33819 MARIPCT4 13.8 49.51 4 Bay Area Contra Costa Aug NQC Market PG&E KIRKER_7_KELCYN 3.22 Bay Area Pittsburg Not modeled Market Not modeled PG&E LAWRNC_7_SUNYVL 0.18 Bay Area None Market Aug NQC San Jose, South PG&E LECEF_1_UNITS 35854 LECEFGT1 13.8 45.97 1 Bay Area Aug NQC Market Bay-Moss Landing San Jose, South PG&E LECEF_1_UNITS 35855 LECEFGT2 13.8 45.97 1 Bay Area Aug NQC Market Bay-Moss Landing San Jose, South PG&E LECEF_1_UNITS 35856 LECEFGT3 13.8 45.97 1 Bay Area Aug NQC Market Bay-Moss Landing San Jose, South PG&E LECEF_1_UNITS 35857 LECEFGT4 13.8 45.97 1 Bay Area Aug NQC Market Bay-Moss Landing San Jose, South PG&E LECEF_1_UNITS 35858 LECEFST1 13.8 110.33 1 Bay Area Market Bay-Moss Landing PG&E LMBEPK_2_UNITA1 32173 LAMBGT1 13.8 48.00 1 Bay Area Contra Costa Aug NQC Market PG&E LMBEPK_2_UNITA2 32174 GOOSEHGT 13.8 48.00 2 Bay Area Contra Costa Aug NQC Market PG&E LMBEPK_2_UNITA3 32175 CREEDGT1 13.8 48.00 3 Bay Area Contra Costa Aug NQC Market PG&E LMEC_1_PL1X3 33112 LMECCT1 18 160.07 1 Bay Area Pittsburg Aug NQC Market PG&E LMEC_1_PL1X3 33111 LMECCT2 18 160.07 1 Bay Area Pittsburg Aug NQC Market PG&E LMEC_1_PL1X3 33113 LMECST1 18 235.85 1 Bay Area Pittsburg Aug NQC Market Not modeled PG&E MARTIN_1_SUNSET 1.85 Bay Area None QF/Selfgen Aug NQC Not modeled PG&E METCLF_1_QF 0.08 Bay Area None QF/Selfgen Aug NQC South Bay-Moss PG&E METEC_2_PL1X3 35881 MEC CTG1 18 178.43 1 Bay Area Aug NQC Market Landing South Bay-Moss PG&E METEC_2_PL1X3 35882 MEC CTG2 18 178.43 1 Bay Area Aug NQC Market Landing South Bay-Moss PG&E METEC_2_PL1X3 35883 MEC STG1 18 213.13 1 Bay Area Aug NQC Market Landing Not modeled PG&E MISSIX_1_QF 0.01 Bay Area None QF/Selfgen Aug NQC San Jose, South Not modeled PG&E MLPTAS_7_QFUNTS 0.04 Bay Area QF/Selfgen Bay-Moss Landing Aug NQC

133 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Not modeled PG&E MOSSLD_1_QF 0.00 Bay Area Market Aug NQC South Bay-Moss 78% starting PG&E MOSSLD_2_PSP1 36221 DUKMOSS1 18 163.20 1 Bay Area Market Landing 2021 South Bay-Moss 78% starting PG&E MOSSLD_2_PSP1 36222 DUKMOSS2 18 163.20 1 Bay Area Market Landing 2021 South Bay-Moss 78% starting PG&E MOSSLD_2_PSP1 36223 DUKMOSS3 18 183.60 1 Bay Area Market Landing 2021 South Bay-Moss 78% starting PG&E MOSSLD_2_PSP2 36224 DUKMOSS4 18 163.20 1 Bay Area Market Landing 2021 South Bay-Moss 78% starting PG&E MOSSLD_2_PSP2 36225 DUKMOSS5 18 163.20 1 Bay Area Market Landing 2021 South Bay-Moss 78% starting PG&E MOSSLD_2_PSP2 36226 DUKMOSS6 18 183.60 1 Bay Area Market Landing 2021 Not modeled PG&E NEWARK_1_QF 0.29 Bay Area None QF/Selfgen Aug NQC Not modeled PG&E OAK C_1_EBMUD 1.62 Bay Area Oakland MUNI Aug NQC PG&E OAK C_7_UNIT 1 32901 OAKLND 1 13.8 55.00 1 Bay Area Oakland Market PG&E OAK C_7_UNIT 2 32902 OAKLND 2 13.8 55.00 1 Bay Area Oakland Market PG&E OAK C_7_UNIT 3 32903 OAKLND 3 13.8 55.00 1 Bay Area Oakland Market Not modeled PG&E OAK L_1_GTG1 0.00 Bay Area Oakland Market Energy Only PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 1 Bay Area Ames Market PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 2 Bay Area Ames Market PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 3 Bay Area Ames Market PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 4 Bay Area Ames Market PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 5 Bay Area Ames Market PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 6 Bay Area Ames Market PG&E OXMTN_6_LNDFIL 33469 OX_MTN 4.16 1.45 7 Bay Area Ames Market PG&E PALALT_7_COBUG 4.50 Bay Area None Not modeled MUNI Not modeled PG&E RICHMN_1_CHVSR2 3.48 Bay Area None Market Aug NQC Not modeled PG&E RICHMN_1_SOLAR 0.82 Bay Area None Market Aug NQC Not modeled PG&E RICHMN_7_BAYENV 2.00 Bay Area None Market Aug NQC

134 / 226 Appendix A - List of physical resources by PTO, local area and market ID

No NQC - PG&E RUSCTY_2_UNITS 35304 RUSELCT1 15 186.97 1 Bay Area Ames Market Pmax No NQC - PG&E RUSCTY_2_UNITS 35305 RUSELCT2 15 186.97 2 Bay Area Ames Market Pmax No NQC - PG&E RUSCTY_2_UNITS 35306 RUSELST1 15 246.06 3 Bay Area Ames Market Pmax PG&E RVRVEW_1_UNITA1 33178 RVEC_GEN 13.8 48.70 1 Bay Area Contra Costa Aug NQC Market PG&E SRINTL_6_UNIT 33468 SRI INTL 9.11 0.34 1 Bay Area None Aug NQC QF/Selfgen PG&E STAUFF_1_UNIT 33139 STAUFER 9.11 0.02 1 Bay Area None Aug NQC QF/Selfgen PG&E STOILS_1_UNITS 32921 CHEVGEN1 13.8 1.22 1 Bay Area Pittsburg Aug NQC Market PG&E STOILS_1_UNITS 32922 CHEVGEN2 13.8 1.22 1 Bay Area Pittsburg Aug NQC Market PG&E STOILS_1_UNITS 32923 CHEVGEN3 13.8 0.57 3 Bay Area Pittsburg Aug NQC Market PG&E TIDWTR_2_UNITS 33151 FOSTER W 12.5 3.57 1 Bay Area Pittsburg Aug NQC Net Seller PG&E TIDWTR_2_UNITS 33151 FOSTER W 12.5 3.57 2 Bay Area Pittsburg Aug NQC Net Seller PG&E TIDWTR_2_UNITS 33151 FOSTER W 12.5 2.71 3 Bay Area Pittsburg Aug NQC Net Seller PG&E UNCHEM_1_UNIT 32920 UNION CH 9.11 11.07 1 Bay Area Pittsburg Aug NQC QF/Selfgen PG&E UNOCAL_1_UNITS 32910 UNOCAL 12 0.25 1 Bay Area Pittsburg Aug NQC QF/Selfgen PG&E UNOCAL_1_UNITS 32910 UNOCAL 12 0.25 2 Bay Area Pittsburg Aug NQC QF/Selfgen PG&E UNOCAL_1_UNITS 32910 UNOCAL 12 0.25 3 Bay Area Pittsburg Aug NQC QF/Selfgen PG&E USWNDR_2_SMUD 32169 SOLANOWP 21 27.08 1 Bay Area Contra Costa Aug NQC Wind PG&E USWNDR_2_SMUD2 32186 SOLANO 34.5 33.87 1 Bay Area Contra Costa Aug NQC Wind PG&E USWNDR_2_UNITS 32168 EXNCO 9.11 15.79 1 Bay Area Contra Costa Aug NQC Wind PG&E USWPJR_2_UNITS 39233 GRNRDG 0.69 20.72 1 Bay Area Contra Costa Aug NQC Wind PG&E WNDMAS_2_UNIT 1 33170 WINDMSTR 9.11 10.07 1 Bay Area Contra Costa Aug NQC Wind PG&E ZOND_6_UNIT 35316 ZOND SYS 9.11 4.53 1 Bay Area Contra Costa Aug NQC Wind San Jose, South No NQC - PG&E ZZ_IBMCTL_1_UNIT 1 35637 IBM-CTLE 115 0.00 1 Bay Area Market Bay-Moss Landing hist. data No NQC - PG&E ZZ_IMHOFF_1_UNIT 1 33136 CCCSD 12.5 0.00 1 Bay Area Pittsburg QF/Selfgen hist. data No NQC - PG&E ZZ_LFC 51_2_UNIT 1 35310 PPASSWND 21 0.00 1 Bay Area None Wind est. data San Jose, South PG&E ZZ_MARKHM_1_CATLST 35863 CATALYST 9.11 0.00 1 Bay Area QF/Selfgen Bay-Moss Landing San Jose, South No NQC - PG&E ZZ_NA 35861 SJ-SCL W 4.3 0.00 1 Bay Area QF/Selfgen Bay-Moss Landing hist. data

135 / 226 Appendix A - List of physical resources by PTO, local area and market ID

South Bay-Moss PG&E ZZ_NA 36209 SLD ENRG 12.5 0.00 1 Bay Area QF/Selfgen Landing No NQC - PG&E ZZ_SEAWST_6_LAPOS 35312 FOREBAYW 22 0.00 1 Bay Area Contra Costa Wind est. data No NQC - PG&E ZZ_SHELRF_1_UNITS 33141 SHELL 1 12.5 0.00 1 Bay Area Pittsburg Net Seller hist. data No NQC - PG&E ZZ_SHELRF_1_UNITS 33142 SHELL 2 12.5 0.00 1 Bay Area Pittsburg Net Seller hist. data No NQC - PG&E ZZ_SHELRF_1_UNITS 33143 SHELL 3 12.5 0.00 1 Bay Area Pittsburg Net Seller hist. data

PG&E ZZ_USWPFK_6_FRICK 35320 FRICKWND 12 1.90 1 Bay Area Contra Costa Aug NQC Wind

PG&E ZZ_USWPFK_6_FRICK 35320 FRICKWND 12 0.00 2 Bay Area Contra Costa Aug NQC Wind

San Jose, South No NQC - PG&E ZZ_ZANKER_1_UNIT 1 35861 SJ-SCL W 4.3 0.00 RN Bay Area QF/Selfgen Bay-Moss Landing hist. data No NQC - PG&E ZZZ_New Unit 35623 SWIFT 21 4.00 BT Bay Area Battery Pmax No NQC - PG&E ZZZ_New Unit 30522 0354-WD 21 1.83 EW Bay Area Contra Costa Market Pmax PG&E ZZZ_New Unit 35307 A100US-L 12.6 0.00 RN Bay Area Energy Only Market PG&E ZZZ_New Unit 35859 HGST-LV 12.4 0.00 RN Bay Area Energy Only Market PG&E ZZZ_New Unit 35302 NUMMI-LV 12.6 0.00 RN Bay Area Energy Only Market ZZZZZZ_COCOPP_7_UNI 33116 C.COS 6 18 0.00 RT Bay Area Contra Costa Retired Market PG&E T 6 ZZZZZZ_COCOPP_7_UNI 33117 C.COS 7 18 0.00 RT Bay Area Contra Costa Retired Market PG&E T 7 ZZZZZZ_CONTAN_1_UNI San Jose, South 36856 CCA100 13.8 0.00 1 Bay Area Retired MUNI PG&E T Bay-Moss Landing ZZZZZZ_FLOWD1_6_ALT 35318 FLOWDPTR 9.11 0.00 1 Bay Area Contra Costa Retired Wind PG&E PP1 ZZZZZZ_MOSSLD_7_UNI South Bay-Moss 36405 MOSSLND6 22 0.00 1 Bay Area Retired Market PG&E T 6 Landing ZZZZZZ_MOSSLD_7_UNI South Bay-Moss 36406 MOSSLND7 22 0.00 1 Bay Area Retired Market PG&E T 7 Landing ZZZZZZ_PITTSP_7_UNIT 33105 PTSB 5 18 0.00 RT Bay Area Pittsburg Retired Market PG&E 5 ZZZZZZ_PITTSP_7_UNIT 33106 PTSB 6 18 0.00 RT Bay Area Pittsburg Retired Market PG&E 6

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ZZZZZZ_PITTSP_7_UNIT 30000 PTSB 7 20 0.00 RT Bay Area Pittsburg Retired Market PG&E 7 ZZZZZZ_UNTDQF_7_UNI 33466 UNTED CO 9.11 0.00 1 Bay Area None Retired QF/Selfgen PG&E TS PG&E ADERA_1_SOLAR1 34319 Q644 0.48 0.00 1 Fresno Wilson, Herndon Aug NQC Market PG&E ADMEST_6_SOLAR 34315 ADAMS_E 12.5 0.00 1 Fresno Wilson, Herndon Energy Only Market PG&E AGRICO_6_PL3N5 34608 AGRICO 13.8 22.69 3 Fresno Wilson, Herndon Market PG&E AGRICO_7_UNIT 34608 AGRICO 13.8 7.47 2 Fresno Wilson, Herndon Market PG&E AGRICO_7_UNIT 34608 AGRICO 13.8 43.13 4 Fresno Wilson, Herndon Market PG&E AVENAL_6_AVPARK 34265 AVENAL P 12 0.00 1 Fresno Wilson, Coalinga Energy Only Market Not modeled PG&E AVENAL_6_AVSLR1 0.00 Fresno Wilson, Coalinga Market Energy Only Not modeled PG&E AVENAL_6_AVSLR2 0.00 Fresno Wilson, Coalinga Market Energy Only PG&E AVENAL_6_SANDDG 34263 SANDDRAG 12 0.00 1 Fresno Wilson, Coalinga Energy Only Market PG&E AVENAL_6_SUNCTY 34257 SUNCTY D 12 0.00 1 Fresno Wilson, Coalinga Energy Only Market PG&E BALCHS_7_UNIT 1 34624 BALCH 13.2 33.00 1 Fresno Wilson, Herndon Aug NQC Market PG&E BALCHS_7_UNIT 2 34612 BLCH 13.8 52.50 1 Fresno Wilson, Herndon Aug NQC Market PG&E BALCHS_7_UNIT 3 34614 BLCH 13.8 52.50 1 Fresno Wilson, Herndon Aug NQC Market PG&E CANTUA_1_SOLAR 34349 CANTUA_D 12.5 4.10 1 Fresno Wilson Aug NQC Market PG&E CANTUA_1_SOLAR 34349 CANTUA_D 12.5 4.10 2 Fresno Wilson Aug NQC Market PG&E CAPMAD_1_UNIT 1 34179 MADERA_G 13.8 4.29 1 Fresno Wilson Market PG&E CHEVCO_6_UNIT 1 34652 CHV.COAL 9.11 1.70 1 Fresno Wilson, Coalinga Aug NQC QF/Selfgen PG&E CHEVCO_6_UNIT 2 34652 CHV.COAL 9.11 0.93 2 Fresno Wilson, Coalinga Aug NQC QF/Selfgen PG&E CHWCHL_1_BIOMAS 34305 CHWCHLA2 13.8 9.78 1 Fresno Wilson, Herndon Aug NQC Market PG&E CHWCHL_1_UNIT 34301 CHOWCOGN 13.8 48.00 1 Fresno Wilson, Herndon Market PG&E COLGA1_6_SHELLW 34654 COLNGAGN 9.11 34.70 1 Fresno Wilson, Coalinga Aug NQC Net Seller Wilson, Herndon, Not Modeled PG&E CORCAN_1_SOLAR1 8.20 Fresno Market Hanford Aug NQC Wilson, Herndon, Not Modeled PG&E CORCAN_1_SOLAR2 4.51 Fresno Market Hanford Aug NQC Not modeled PG&E CRESSY_1_PARKER 34140 CRESSEY 115 0.73 Fresno Wilson MUNI Aug NQC PG&E CRNEVL_6_CRNVA 34634 CRANEVLY 12 0.90 1 Fresno Wilson, Borden Aug NQC Market PG&E CRNEVL_6_SJQN 2 34631 SJ2GEN 9.11 3.20 1 Fresno Wilson, Borden Aug NQC Market PG&E CRNEVL_6_SJQN 3 34633 SJ3GEN 9.11 4.20 1 Fresno Wilson, Borden Aug NQC Market

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Not modeled PG&E CURTIS_1_CANLCK 0.13 Fresno Wilson Market Aug NQC Not modeled PG&E CURTIS_1_FARFLD 0.30 Fresno Wilson Market Aug NQC Wilson, Herndon, PG&E DINUBA_6_UNIT 34648 DINUBA E 13.8 3.93 1 Fresno Market Reedley PG&E EEKTMN_6_SOLAR1 34627 KETTLEMN 0.34 0.00 1 Fresno Wilson Energy Only Market Not Modeled PG&E ELCAP_1_SOLAR 0.62 Fresno Wilson Market Aug NQC PG&E ELNIDP_6_BIOMAS 34330 ELNIDO 13.8 9.40 1 Fresno Wilson Aug NQC Market PG&E EXCHEC_7_UNIT 1 34306 EXCHQUER 13.8 90.72 1 Fresno Wilson Aug NQC MUNI PG&E EXCLSG_1_SOLAR 34623 Q678 0.5 24.60 1 Fresno Wilson Aug NQC Market PG&E FRESHW_1_SOLAR1 34669 Q529A 4.16 0.00 1 Fresno Wilson, Herndon Energy Only Market PG&E FRESHW_1_SOLAR1 34669 Q529A 0.48 0.00 2 Fresno Wilson, Herndon Energy Only Market PG&E FRIANT_6_UNITS 34636 FRIANTDM 6.6 5.76 2 Fresno Wilson, Borden Aug NQC Net Seller PG&E FRIANT_6_UNITS 34636 FRIANTDM 6.6 3.08 3 Fresno Wilson, Borden Aug NQC Net Seller PG&E FRIANT_6_UNITS 34636 FRIANTDM 6.6 0.81 4 Fresno Wilson, Borden Aug NQC Net Seller PG&E GIFENS_6_BUGSL1 34644 Q679 0.55 8.20 1 Fresno Wilson Aug NQC Market Not modeled PG&E GIFFEN_6_SOLAR 4.10 Fresno Wilson Market Aug NQC PG&E GUERNS_6_SOLAR 34461 GUERNSEY 12.5 4.10 1 Fresno Wilson Aug NQC Market PG&E GUERNS_6_SOLAR 34461 GUERNSEY 12.5 4.10 2 Fresno Wilson Aug NQC Market Wilson, Herndon, PG&E GWFPWR_1_UNITS 34431 GWF_HEP1 13.8 49.23 1 Fresno Market Hanford Wilson, Herndon, PG&E GWFPWR_1_UNITS 34433 GWF_HEP2 13.8 49.23 1 Fresno Market Hanford PG&E HAASPH_7_PL1X2 34610 HAAS 13.8 72.00 1 Fresno Wilson, Herndon Aug NQC Market PG&E HAASPH_7_PL1X2 34610 HAAS 13.8 72.00 2 Fresno Wilson, Herndon Aug NQC Market PG&E HELMPG_7_UNIT 1 34600 HELMS 18 407.00 1 Fresno Wilson Aug NQC Market PG&E HELMPG_7_UNIT 2 34602 HELMS 18 407.00 2 Fresno Wilson Aug NQC Market PG&E HELMPG_7_UNIT 3 34604 HELMS 18 404.00 3 Fresno Wilson Aug NQC Market Not modeled PG&E HENRTA_6_SOLAR1 0.00 Fresno Wilson Market Energy Only Not modeled PG&E HENRTA_6_SOLAR2 0.00 Fresno Wilson Market Energy Only PG&E HENRTA_6_UNITA1 34539 GWF_GT1 13.8 49.98 1 Fresno Wilson Market

138 / 226 Appendix A - List of physical resources by PTO, local area and market ID

PG&E HENRTA_6_UNITA2 34541 GWF_GT2 13.8 49.42 1 Fresno Wilson Market PG&E HENRTS_1_SOLAR 34617 Q581 0.38 41.00 1 Fresno Wilson Aug NQC Market PG&E HURON_6_SOLAR 34557 HURON_DI 12.5 4.10 1 Fresno Wilson, Coalinga Aug NQC Market PG&E HURON_6_SOLAR 34557 HURON_DI 12.5 4.10 2 Fresno Wilson, Coalinga Aug NQC Market PG&E INTTRB_6_UNIT 34342 INT.TURB 9.11 5.63 1 Fresno Wilson Aug NQC QF/Selfgen PG&E JAYNE_6_WLSLR 34639 WESTLNDS 0.48 0.00 1 Fresno Wilson, Coalinga Energy Only Market PG&E KANSAS_6_SOLAR 34666 KANSASS_S 12.5 0.00 F Fresno Wilson Energy Only Market PG&E KERKH1_7_UNIT 1 34344 KERCK1-1 6.6 13.00 1 Fresno Wilson, Herndon Aug NQC Market PG&E KERKH1_7_UNIT 3 34345 KERCK1-3 6.6 12.80 3 Fresno Wilson, Herndon Aug NQC Market PG&E KERKH2_7_UNIT 1 34308 KERCKHOF 13.8 153.90 1 Fresno Wilson, Herndon Aug NQC Market Not modeled PG&E KERMAN_6_SOLAR1 0.00 Fresno Wilson Market Energy Only Not modeled PG&E KERMAN_6_SOLAR2 0.00 Fresno Wilson Market Energy Only Wilson, Herndon, PG&E KINGCO_1_KINGBR 34642 KINGSBUR 9.11 34.50 1 Fresno Aug NQC Net Seller Hanford PG&E KINGRV_7_UNIT 1 34616 KINGSRIV 13.8 51.20 1 Fresno Wilson, Herndon Aug NQC Market Not modeled PG&E KNGBRG_1_KBSLR1 0.00 Fresno Wilson Market Energy Only Not modeled PG&E KNGBRG_1_KBSLR2 0.00 Fresno Wilson Market Energy Only PG&E KNTSTH_6_SOLAR 34694 KENT_S 0.8 0.00 1 Fresno Wilson Energy Only Market PG&E LEPRFD_1_KANSAS 34680 KANSAS 12.5 8.20 1 Fresno Wilson, Hanford Aug NQC Market PG&E MALAGA_1_PL1X2 34671 KRCDPCT1 13.8 48.00 1 Fresno Wilson, Herndon Market PG&E MALAGA_1_PL1X2 34672 KRCDPCT2 13.8 48.00 1 Fresno Wilson, Herndon Market PG&E MCCALL_1_QF 34219 MCCALL 4 12.5 0.44 QF Fresno Wilson, Herndon Aug NQC QF/Selfgen PG&E MCSWAN_6_UNITS 34320 MCSWAIN 9.11 9.60 1 Fresno Wilson Aug NQC MUNI PG&E MENBIO_6_RENEW1 34339 CALRENEW 12.5 2.05 1 Fresno Wilson, Herndon Aug NQC Net Seller PG&E MENBIO_6_UNIT 34334 BIO PWR 9.11 19.24 1 Fresno Wilson Aug NQC QF/Selfgen Not modeled PG&E MERCED_1_SOLAR1 0.00 Fresno Wilson Market Energy Only Not modeled PG&E MERCED_1_SOLAR2 0.00 Fresno Wilson Market Energy Only PG&E MERCFL_6_UNIT 34322 MERCEDFL 9.11 3.36 1 Fresno Wilson Aug NQC Market PG&E MNDOTA_1_SOLAR1 34311 NORTHSTAR 0.2 24.60 1 Fresno Wilson Aug NQC Market

139 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Not modeled PG&E MNDOTA_1_SOLAR2 0.00 Fresno Wilson Market Energy Only PG&E MSTANG_2_SOLAR 34683 Q643W 0.8 12.30 1 Fresno Wilson Aug NQC Market PG&E MSTANG_2_SOLAR3 34683 Q643W 0.8 16.40 1 Fresno Wilson Aug NQC Market PG&E MSTANG_2_SOLAR4 34683 Q643W 0.8 12.30 1 Fresno Wilson Aug NQC Market PG&E ONLLPP_6_UNITS 34316 ONEILPMP 9.11 0.37 1 Fresno Wilson Aug NQC MUNI Not modeled PG&E OROLOM_1_SOLAR1 0.00 Fresno Wilson Market Energy Only Not modeled PG&E OROLOM_1_SOLAR2 0.00 Fresno Wilson Market Energy Only Not modeled PG&E PAIGES_6_SOLAR 0.00 Fresno Wilson Market Energy Only PG&E PINFLT_7_UNITS 38720 PINEFLAT 13.8 70.00 1 Fresno Wilson, Herndon Aug NQC MUNI PG&E PINFLT_7_UNITS 38720 PINEFLAT 13.8 70.00 2 Fresno Wilson, Herndon Aug NQC MUNI PG&E PINFLT_7_UNITS 38720 PINEFLAT 13.8 70.00 3 Fresno Wilson, Herndon Aug NQC MUNI PG&E PNCHPP_1_PL1X2 34328 STARGT1 13.8 59.96 1 Fresno Wilson Market PG&E PNCHPP_1_PL1X2 34329 STARGT2 13.8 59.96 2 Fresno Wilson Market PG&E PNOCHE_1_PL1X2 34142 WHD_PAN2 13.8 49.97 1 Fresno Wilson, Herndon Market PG&E PNOCHE_1_UNITA1 34186 DG_PAN1 13.8 48.00 1 Fresno Wilson Market Wilson, Herndon, Not modeled PG&E REEDLY_6_SOLAR 0.00 Fresno Market Reedley Energy Only Not modeled PG&E S_RITA_6_SOLAR1 0.00 Fresno Wilson Market Energy Only SCHINDLER_ PG&E SCHNDR_1_FIVPTS 34353 12.5 4.10 1 Fresno Wilson, Coalinga Aug NQC Market D SCHINDLER_ PG&E SCHNDR_1_FIVPTS 34353 12.5 2.05 2 Fresno Wilson, Coalinga Aug NQC Market D SCHINDLER_ PG&E SCHNDR_1_WSTSDE 34353 12.5 4.10 3 Fresno Wilson, Coalinga Aug NQC Market D SCHINDLER_ PG&E SCHNDR_1_WSTSDE 34353 12.5 2.05 4 Fresno Wilson, Coalinga Aug NQC Market D PG&E SGREGY_6_SANGER 34646 SANGERCO 13.8 38.77 1 Fresno Wilson Aug NQC Market PG&E SGREGY_6_SANGER 34646 SANGERCO 13.8 9.31 2 Fresno Wilson Aug NQC Market Not modeled PG&E STOREY_2_MDRCH2 34253 BORDEN D 12.5 0.21 QF Fresno Wilson Market Aug NQC Not modeled PG&E STOREY_2_MDRCH3 34253 BORDEN D 12.5 0.18 QF Fresno Wilson Market Aug NQC

140 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Not modeled PG&E STOREY_2_MDRCH4 34253 BORDEN D 12.5 0.27 QF Fresno Wilson Market Aug NQC

PG&E STOREY_7_MDRCHW 34209 STOREY D 12.5 0.21 1 Fresno Wilson Aug NQC Net Seller

PG&E STROUD_6_SOLAR 34563 STROUD_D 12.5 4.10 1 Fresno Wilson, Herndon Aug NQC Market PG&E STROUD_6_SOLAR 34563 STROUD_D 12.5 4.10 2 Fresno Wilson, Herndon Aug NQC Market PG&E TRNQL8_2_AZUSR1 365517 Q1032G2 0.55 8.20 2 Fresno Wilson Aug NQC Market PG&E TRNQLT_2_SOLAR 34340 Q643X 0.8 82.00 1 Fresno Wilson Aug NQC Market PG&E ULTPFR_1_UNIT 1 34640 ULTR.PWR 9.11 24.07 1 Fresno Wilson, Herndon Aug NQC Market PG&E VEGA_6_SOLAR1 34314 VEGA 34.5 0.00 1 Fresno Wilson Energy Only Market CORCORANP Wilson, Herndon, PG&E WAUKNA_1_SOLAR 34696 21 8.20 1 Fresno Aug NQC Market V_S Hanford Wilson, Herndon, No NQC - PG&E WAUKNA_1_SOLAR2 34677 Q558 21 8.10 1 Fresno Market Hanford Pmax Not modeled PG&E WFRESN_1_SOLAR 0.00 Fresno Wilson Market Energy Only PG&E WHITNY_6_SOLAR 34673 Q532 0.55 0.00 1 Fresno Wilson, Coalinga Energy Only Market PG&E WISHON_6_UNITS 34658 WISHON 2.3 4.51 1 Fresno Wilson, Borden Aug NQC Market PG&E WISHON_6_UNITS 34658 WISHON 2.3 4.51 2 Fresno Wilson, Borden Aug NQC Market PG&E WISHON_6_UNITS 34658 WISHON 2.3 4.51 3 Fresno Wilson, Borden Aug NQC Market PG&E WISHON_6_UNITS 34658 WISHON 2.3 4.51 4 Fresno Wilson, Borden Aug NQC Market PG&E WISHON_6_UNITS 34658 WISHON 2.3 0.36 SJ Fresno Wilson, Borden Aug NQC Market Not modeled PG&E WOODWR_1_HYDRO 0.00 Fresno Wilson Market Energy Only PG&E WRGHTP_7_AMENGY 34207 WRIGHT D 12.5 0.03 QF Fresno Wilson Aug NQC QF/Selfgen No NQC - PG&E ZZ_BORDEN_2_QF 34253 BORDEN D 12.5 1.30 QF Fresno Wilson Net Seller hist. data

PG&E ZZ_BULLRD_7_SAGNES 34213 BULLD 12 12.5 0.06 1 Fresno Wilson Aug NQC QF/Selfgen

PG&E ZZ_GATES_6_PL1X2 34553 WHD_GAT2 13.8 0.00 1 Fresno Wilson, Coalinga Market

PG&E ZZ_JRWOOD_1_UNIT 1 34332 JRWCOGEN 9.11 0.00 1 Fresno Wilson QF/Selfgen

No NQC - PG&E ZZ_KERKH1_7_UNIT 2 34343 KERCK1-2 6.6 8.50 2 Fresno Wilson, Herndon Market hist. data No NQC - PG&E ZZ_NA 34485 FRESNOWW 12.5 0.00 1 Fresno Wilson QF/Selfgen hist. data

141 / 226 Appendix A - List of physical resources by PTO, local area and market ID

No NQC - PG&E ZZ_NA 34485 FRESNOWW 12.5 0.10 2 Fresno Wilson QF/Selfgen hist. data No NQC - PG&E ZZ_NA 34485 FRESNOWW 12.5 0.00 3 Fresno Wilson QF/Selfgen hist. data PG&E ZZZ_New Unit 34653 Q526 0.55 0.00 1 Fresno Wilson, Coalinga Energy Only Market No NQC - PG&E ZZZ_New Unit 34467 GIFFEN_DIST 12.5 4.10 1 Fresno Wilson, Herndon Market est. data No NQC - PG&E ZZZ_New Unit 34649 Q965 0.36 5.53 1 Fresno Wilson, Herndon Market est. data No NQC - PG&E ZZZ_New Unit 365514 Q1032G1 0.55 7.87 1 Fresno Wilson Market est. data No NQC - PG&E ZZZ_New Unit 365502 Q632BC1 0.55 8.28 1 Fresno Wilson Market est. data No NQC - PG&E ZZZ_New Unit 34313 NORTHSTAR 0.55 61.60 1 Fresno Wilson Market Pmax No NQC - PG&E ZZZ_New Unit 365520 Q1032G3 0.55 67.49 3 Fresno Wilson Market est. data No NQC - PG&E ZZZ_New Unit 34689 ORO LOMA_3 12.5 20.00 EW Fresno Wilson Market Pmax Wilson, Herndon, No NQC - PG&E ZZZ_New Unit 34690 CORCORAN 12.5 8.20 FW Fresno Market Hanford est. data Wilson, Herndon, No NQC - PG&E ZZZ_New Unit 34692 CORCORAN 12.5 12.00 FW Fresno Market Hanford Pmax No NQC - PG&E ZZZ_New Unit 34651 JACALITO-LV 0.55 1.22 RN Fresno Wilson Market Pmax PG&E ZZZ_New Unit 34603 JGBSWLT 12.5 0.00 ST Fresno Wilson, Herndon Energy Only Market No NQC - ZZZZ_New Unit 34335 Q723 0.32 20.50 1 Fresno Wilson, Borden Market PG&E est. data No NQC - ZZZZ_New Unit 34688 Q272 0.55 50.43 1 Fresno Wilson Market PG&E est. data Not modeled PG&E BRDGVL_7_BAKER 0.88 Humboldt None Net Seller Aug NQC PG&E FAIRHV_6_UNIT 31150 FAIRHAVN 13.8 13.58 1 Humboldt None Aug NQC Net Seller Not modeled PG&E FTSWRD_6_TRFORK 0.10 Humboldt None Market Aug NQC Not modeled PG&E FTSWRD_7_QFUNTS 0.00 Humboldt None QF/Selfgen Aug NQC PG&E HUMBPP_1_UNITS3 31180 HUMB_G1 13.8 16.30 1 Humboldt None Market PG&E HUMBPP_1_UNITS3 31180 HUMB_G1 13.8 15.83 2 Humboldt None Market

142 / 226 Appendix A - List of physical resources by PTO, local area and market ID

PG&E HUMBPP_1_UNITS3 31180 HUMB_G1 13.8 16.67 3 Humboldt None Market PG&E HUMBPP_1_UNITS3 31180 HUMB_G1 13.8 16.20 4 Humboldt None Market PG&E HUMBPP_6_UNITS 31181 HUMB_G2 13.8 16.14 5 Humboldt None Market PG&E HUMBPP_6_UNITS 31181 HUMB_G2 13.8 16.33 6 Humboldt None Market PG&E HUMBPP_6_UNITS 31181 HUMB_G2 13.8 16.24 7 Humboldt None Market PG&E HUMBPP_6_UNITS 31182 HUMB_G3 13.8 16.62 8 Humboldt None Market PG&E HUMBPP_6_UNITS 31182 HUMB_G3 13.8 16.33 9 Humboldt None Market PG&E HUMBPP_6_UNITS 31182 HUMB_G3 13.8 15.95 10 Humboldt None Market Not modeled PG&E HUMBSB_1_QF 0.00 Humboldt None QF/Selfgen Aug NQC PG&E KEKAWK_6_UNIT 31166 KEKAWAK 9.1 0.80 1 Humboldt None Aug NQC Net Seller PG&E LAPAC_6_UNIT 31158 LP SAMOA 12.5 0.00 1 Humboldt None Market Not modeled PG&E LOWGAP_1_SUPHR 0.00 Humboldt None Market Aug NQC PG&E PACLUM_6_UNIT 31152 PAC.LUMB 13.8 9.31 1 Humboldt None Aug NQC Net Seller PG&E PACLUM_6_UNIT 31152 PAC.LUMB 13.8 9.31 2 Humboldt None Aug NQC Net Seller PG&E PACLUM_6_UNIT 31153 PAC.LUMB 2.4 5.59 3 Humboldt None Aug NQC Net Seller ZZZZZ_BLULKE_6_BLUEL 31156 BLUELKPP 12.5 0.00 1 Humboldt None Retired Market PG&E K South Kern PP, PG&E 7STDRD_1_SOLAR1 35065 7STNDRD_1 21 8.20 FW Kern Aug NQC Market Kern Oil PG&E ADOBEE_1_SOLAR 35021 Q622B 34.5 8.20 1 Kern South Kern PP Aug NQC Market PG&E BDGRCK_1_UNITS 35029 BADGERCK 13.8 43.00 1 Kern South Kern PP Aug NQC Net Seller South Kern PP, PG&E BEARMT_1_UNIT 35066 PSE-BEAR 13.8 45.00 1 Kern Aug NQC Net Seller Westpark Not modeled PG&E BKRFLD_2_SOLAR1 0.57 Kern South Kern PP Market Aug NQC South Kern PP, PG&E DEXZEL_1_UNIT 35024 DEXEL + 13.8 17.15 1 Kern Aug NQC Net Seller Kern Oil South Kern PP, PG&E DISCOV_1_CHEVRN 35062 DISCOVRY 13.8 3.04 1 Kern Aug NQC QF/Selfgen Kern Oil PG&E DOUBLC_1_UNITS 35023 DOUBLE C 13.8 51.20 1 Kern South Kern PP Aug NQC Net Seller PG&E KERNFT_1_UNITS 35026 KERNFRNT 9.11 51.30 1 Kern South Kern PP Aug NQC Net Seller PG&E KRNCNY_6_UNIT 35018 KERNCNYN 11 3.42 1 Kern South Kern PP Aug NQC Market PG&E LAMONT_1_SOLAR1 35019 REGULUS 0.4 24.60 1 Kern South Kern PP Aug NQC Market PG&E LAMONT_1_SOLAR2 35092 Q744G4 0.38 8.20 1 Kern South Kern PP Aug NQC Market

143 / 226 Appendix A - List of physical resources by PTO, local area and market ID

PG&E LAMONT_1_SOLAR3 35087 Q744G3 0.4 6.15 3 Kern South Kern PP Aug NQC Market PG&E LAMONT_1_SOLAR4 35059 Q744G2 0.4 22.06 2 Kern South Kern PP Aug NQC Market PG&E LAMONT_1_SOLAR5 35054 Q744G1 0.4 6.83 1 Kern South Kern PP Aug NQC Market South Kern PP, PG&E LIVOAK_1_UNIT 1 35058 PSE-LVOK 9.1 42.70 1 Kern Aug NQC Net Seller Kern Oil South Kern PP, Not modeled PG&E MAGUND_1_BKISR1 0.00 Kern Market Kern Oil Aug NQC South Kern PP, Not modeled PG&E MAGUND_1_BKSSR2 2.15 Kern Market Kern Oil Aug NQC South Kern PP, PG&E MTNPOS_1_UNIT 35036 MT POSO 13.8 46.64 1 Kern Aug NQC Net Seller Kern Oil Not modeled PG&E OLDRIV_6_BIOGAS 1.62 Kern South Kern PP Market Aug NQC PG&E OLDRV1_6_SOLAR 35091 OLD_RVR1 12.5 8.20 1 Kern South Kern PP Aug NQC Market PG&E RIOBRV_6_UNIT 1 35020 RIOBRAVO 9.1 1.26 1 Kern South Kern PP Aug NQC Market PG&E SIERRA_1_UNITS 35027 HISIERRA 9.11 51.60 1 Kern South Kern PP Aug NQC Market PG&E SKERN_6_SOLAR1 35089 S_KERN 0.48 8.20 1 Kern South Kern PP Aug NQC Market PG&E SKERN_6_SOLAR2 365563 Q885 0.36 4.10 1 Kern South Kern PP Aug NQC Market South Kern PP, PG&E VEDDER_1_SEKERN 35046 SEKR 9.11 9.46 1 Kern Aug NQC QF/Selfgen Kern Oil South Kern PP, ZZZZZ_OILDAL_1_UNIT 1 35028 OILDALE 9.11 0.00 RT Kern Retired Net Seller PG&E Kern Oil South Kern PP, ZZZZZ_ULTOGL_1_POSO 35035 ULTR PWR 9.11 0.00 1 Kern Retired QF/Selfgen PG&E Kern Oil Eagle Rock, PG&E ADLIN_1_UNITS 31435 GEO.ENGY 9.1 8.00 1 NCNB Market Fulton, Lakeville Eagle Rock, PG&E ADLIN_1_UNITS 31435 GEO.ENGY 9.1 8.00 2 NCNB Market Fulton, Lakeville Eagle Rock, Not modeled PG&E CLOVDL_1_SOLAR 0.00 NCNB Market Fulton, Lakeville Aug NQC Not modeled PG&E CSTOGA_6_LNDFIL 0.00 NCNB Fulton, Lakeville Market Energy Only Not modeled PG&E FULTON_1_QF 0.01 NCNB Fulton, Lakeville QF/Selfgen Aug NQC Eagle Rock, PG&E GEYS11_7_UNIT11 31412 GEYSER11 13.8 68.00 1 NCNB Market Fulton, Lakeville PG&E GEYS12_7_UNIT12 31414 GEYSER12 13.8 50.00 1 NCNB Fulton, Lakeville Market PG&E GEYS13_7_UNIT13 31416 GEYSER13 13.8 56.00 1 NCNB Lakeville Market

144 / 226 Appendix A - List of physical resources by PTO, local area and market ID

PG&E GEYS14_7_UNIT14 31418 GEYSER14 13.8 50.00 1 NCNB Fulton, Lakeville Market PG&E GEYS16_7_UNIT16 31420 GEYSER16 13.8 49.00 1 NCNB Fulton, Lakeville Market PG&E GEYS17_7_UNIT17 31422 GEYSER17 13.8 56.00 1 NCNB Fulton, Lakeville Market PG&E GEYS18_7_UNIT18 31424 GEYSER18 13.8 45.00 1 NCNB Lakeville Market PG&E GEYS20_7_UNIT20 31426 GEYSER20 13.8 40.00 1 NCNB Lakeville Market Eagle Rock, PG&E GYS5X6_7_UNITS 31406 GEYSR5-6 13.8 42.50 1 NCNB Market Fulton, Lakeville Eagle Rock, PG&E GYS5X6_7_UNITS 31406 GEYSR5-6 13.8 42.50 2 NCNB Market Fulton, Lakeville Eagle Rock, PG&E GYS7X8_7_UNITS 31408 GEYSER78 13.8 38.00 1 NCNB Market Fulton, Lakeville Eagle Rock, PG&E GYS7X8_7_UNITS 31408 GEYSER78 13.8 38.00 2 NCNB Market Fulton, Lakeville Not modeled PG&E GYSRVL_7_WSPRNG 1.34 NCNB Fulton, Lakeville QF/Selfgen Aug NQC Not Eagle Rock, PG&E HILAND_7_YOLOWD 0.00 NCNB Modeled. Market Fulton, Lakeville Energy Only Not modeled PG&E IGNACO_1_QF 0.13 NCNB Lakeville QF/Selfgen Aug NQC Eagle Rock, PG&E INDVLY_1_UNITS 31436 INDIAN V 9.1 1.11 1 NCNB Aug NQC Net Seller Fulton, Lakeville PG&E MONTPH_7_UNITS 32700 MONTICLO 9.1 3.03 1 NCNB Fulton, Lakeville Aug NQC Market PG&E MONTPH_7_UNITS 32700 MONTICLO 9.1 3.03 2 NCNB Fulton, Lakeville Aug NQC Market PG&E MONTPH_7_UNITS 32700 MONTICLO 9.1 0.91 3 NCNB Fulton, Lakeville Aug NQC Market PG&E NCPA_7_GP1UN1 38106 NCPA1GY1 13.8 31.00 1 NCNB Lakeville Aug NQC MUNI PG&E NCPA_7_GP1UN2 38108 NCPA1GY2 13.8 28.00 1 NCNB Lakeville Aug NQC MUNI PG&E NCPA_7_GP2UN3 38110 NCPA2GY1 13.8 0.00 1 NCNB Fulton, Lakeville Aug NQC MUNI PG&E NCPA_7_GP2UN4 38112 NCPA2GY2 13.8 52.73 1 NCNB Fulton, Lakeville Aug NQC MUNI Eagle Rock, PG&E POTTER_6_UNITS 31433 POTTRVLY 2.4 0.97 1 NCNB Aug NQC Market Fulton, Lakeville Eagle Rock, PG&E POTTER_6_UNITS 31433 POTTRVLY 2.4 0.44 3 NCNB Aug NQC Market Fulton, Lakeville Eagle Rock, PG&E POTTER_6_UNITS 31433 POTTRVLY 2.4 0.44 4 NCNB Aug NQC Market Fulton, Lakeville Eagle Rock, Not modeled PG&E POTTER_7_VECINO 0.00 NCNB QF/Selfgen Fulton, Lakeville Aug NQC PG&E SANTFG_7_UNITS 31400 SANTA FE 13.8 31.50 1 NCNB Lakeville Market

145 / 226 Appendix A - List of physical resources by PTO, local area and market ID

PG&E SANTFG_7_UNITS 31400 SANTA FE 13.8 31.50 2 NCNB Lakeville Market PG&E SMUDGO_7_UNIT 1 31430 SMUDGEO1 13.8 47.00 1 NCNB Lakeville Market PG&E SNMALF_6_UNITS 31446 SONMA LF 9.1 3.92 1 NCNB Fulton, Lakeville Aug NQC QF/Selfgen Eagle Rock, PG&E UKIAH_7_LAKEMN 38020 CITY UKH 115 0.49 1 NCNB Aug NQC MUNI Fulton, Lakeville Eagle Rock, PG&E UKIAH_7_LAKEMN 38020 CITY UKH 115 1.21 2 NCNB Aug NQC MUNI Fulton, Lakeville PG&E WDFRDF_2_UNITS 31404 WEST FOR 13.8 12.50 1 NCNB Fulton, Lakeville Market PG&E WDFRDF_2_UNITS 31404 WEST FOR 13.8 12.50 2 NCNB Fulton, Lakeville Market Eagle Rock, No NQC - PG&E ZZZ_New Unit 365542 Q1221 13.8 35.00 1 NCNB Market Fulton, Lakeville Pmax ZZZZZ_BEARCN_2_UNIT 31402 BEAR CAN 13.8 0.00 1 NCNB Fulton, Lakeville Retired Market PG&E S ZZZZZ_BEARCN_2_UNIT 31402 BEAR CAN 13.8 0.00 2 NCNB Fulton, Lakeville Retired Market PG&E S ZZZZZZ_GEYS17_2_BOT 31421 BOTTLERK 13.8 0.00 1 NCNB Fulton, Lakeville Retired Market PG&E RCK South of Table Not modeled PG&E ALLGNY_6_HYDRO1 0.08 Sierra Market Mountain Aug NQC Placerville, South of Rio Oso, South Not modeled PG&E APLHIL_1_SLABCK 0.00 1 Sierra Market of Palermo, South Energy Only of Table Mountain South of Table Not modeled PG&E BANGOR_6_HYDRO 0.32 Sierra Market Mountain Aug NQC South of Palermo, PG&E BELDEN_7_UNIT 1 31784 BELDEN 13.8 119.00 1 Sierra South of Table Aug NQC Market Mountain Drum-Rio Oso, South of Palermo, PG&E BIOMAS_1_UNIT 1 32156 WOODLAND 9.11 24.94 1 Sierra Aug NQC Net Seller South of Table Mountain Weimer, Placer, Drum-Rio Oso, South of Rio Oso, Not modeled PG&E BNNIEN_7_ALTAPH 32376 BONNIE N 60 0.56 Sierra Market South of Palermo, Aug NQC South of Table Mountain Bogue, Drum-Rio PG&E BOGUE_1_UNITA1 32451 FREC 13.8 47.60 1 Sierra Oso, South of Aug NQC Market Table Mountain

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Drum-Rio Oso, South of Palermo, PG&E BOWMN_6_HYDRO 32480 BOWMAN 9.11 1.57 1 Sierra Aug NQC MUNI South of Table Mountain South of Palermo, Not modeled PG&E BUCKCK_2_HYDRO 0.29 Sierra South of Table Market Aug NQC Mountain South of Palermo, Not modeled PG&E BUCKCK_7_OAKFLT 1.30 Sierra South of Table Market Aug NQC Mountain South of Palermo, PG&E BUCKCK_7_PL1X2 31820 BCKS CRK 11 30.63 1 Sierra South of Table Aug NQC Market Mountain South of Palermo, PG&E BUCKCK_7_PL1X2 31820 BCKS CRK 11 26.62 2 Sierra South of Table Aug NQC Market Mountain South of Table PG&E CAMPFW_7_FARWST 32470 CMP.FARW 9.11 2.90 1 Sierra Aug NQC MUNI Mountain Placer, Drum-Rio Oso, South of Rio PG&E CHICPK_7_UNIT 1 32462 CHI.PARK 11.5 42.00 1 Sierra Oso, South of Aug NQC MUNI Palermo, South of Table Mountain South of Table PG&E COLGAT_7_UNIT 1 32450 COLGATE1 13.8 161.65 1 Sierra Aug NQC MUNI Mountain South of Table PG&E COLGAT_7_UNIT 2 32452 COLGATE2 13.8 161.68 1 Sierra Aug NQC MUNI Mountain South of Palermo, PG&E CRESTA_7_PL1X2 31812 CRESTA 11.5 34.66 1 Sierra South of Table Aug NQC Market Mountain South of Palermo, PG&E CRESTA_7_PL1X2 31812 CRESTA 11.5 35.34 2 Sierra South of Table Aug NQC Market Mountain Drum-Rio Oso, South of Palermo, Not modeled PG&E DAVIS_1_SOLAR1 0.41 Sierra Market South of Table Aug NQC Mountain Drum-Rio Oso, South of Palermo, Not modeled PG&E DAVIS_1_SOLAR2 0.41 Sierra Market South of Table Aug NQC Mountain Drum-Rio Oso, Not modeled PG&E DAVIS_7_MNMETH 1.80 Sierra Market South of Palermo, Aug NQC

147 / 226 Appendix A - List of physical resources by PTO, local area and market ID

South of Table Mountain

Drum-Rio Oso, PG&E DEADCK_1_UNIT 31862 DEADWOOD 9.11 0.00 1 Sierra South of Table Aug NQC MUNI Mountain Drum-Rio Oso, South of Palermo, PG&E DEERCR_6_UNIT 1 32474 DEER CRK 9.11 7.00 1 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E DRUM_7_PL1X2 32504 DRUM 1-2 6.6 13.00 1 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E DRUM_7_PL1X2 32504 DRUM 1-2 6.6 13.00 2 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E DRUM_7_PL3X4 32506 DRUM 3-4 6.6 13.26 1 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E DRUM_7_PL3X4 32506 DRUM 3-4 6.6 15.64 2 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E DRUM_7_UNIT 5 32454 DRUM 5 13.8 50.00 1 Sierra Aug NQC Market South of Table Mountain Placer, Drum-Rio Oso, South of Rio PG&E DUTCH1_7_UNIT 1 32464 DTCHFLT1 11 22.00 1 Sierra Oso, South of Aug NQC Market Palermo, South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E DUTCH2_7_UNIT 1 32502 DTCHFLT2 6.9 26.00 1 Sierra Aug NQC MUNI South of Table Mountain Placerville, South of Rio Oso, South PG&E ELDORO_7_UNIT 1 32513 ELDRADO1 21.6 11.00 1 Sierra Market of Palermo, South of Table Mountain

148 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Placerville, South of Rio Oso, South PG&E ELDORO_7_UNIT 2 32514 ELDRADO2 21.6 11.00 1 Sierra Market of Palermo, South of Table Mountain South of Rio Oso, South of Palermo, PG&E FMEADO_6_HELLHL 32486 HELLHOLE 9.11 0.32 1 Sierra Aug NQC MUNI South of Table Mountain South of Rio Oso, South of Palermo, PG&E FMEADO_7_UNIT 32508 FRNCH MD 4.2 16.00 1 Sierra Aug NQC MUNI South of Table Mountain Drum-Rio Oso, PG&E FORBST_7_UNIT 1 31814 FORBSTWN 11.5 37.50 1 Sierra South of Table Aug NQC MUNI Mountain Placerville, South of Rio Oso, South PG&E GOLDHL_1_QF 0.33 Sierra Not modeled QF/Selfgen of Palermo, South of Table Mountain Pease, South of PG&E GRIDLY_6_SOLAR 38054 GRIDLEY 60 0.00 1 Sierra Energy Only Market Table Mountain Bogue, Drum-Rio PG&E GRNLF1_1_UNITS 32490 GRNLEAF1 13.8 33.36 1 Sierra Oso, South of Aug NQC Market Table Mountain Bogue, Drum-Rio PG&E GRNLF1_1_UNITS 32491 GRNLEAF1 13.8 15.84 2 Sierra Oso, South of Aug NQC Market Table Mountain Pease, Drum-Rio PG&E GRNLF2_1_UNIT 32492 GRNLEAF2 13.8 36.45 1 Sierra Oso, South of Aug NQC QF/Selfgen Table Mountain Placer, Drum-Rio Oso, South of Rio PG&E HALSEY_6_UNIT 32478 HALSEY F 9.11 13.50 1 Sierra Oso, South of Aug NQC Market Palermo, South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E HAYPRS_6_QFUNTS 32488 HAYPRES+ 9.11 0.00 1 Sierra Aug NQC QF/Selfgen South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E HAYPRS_6_QFUNTS 32488 HAYPRES+ 9.11 0.00 2 Sierra Aug NQC QF/Selfgen South of Table Mountain

149 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Drum-Rio Oso, South of Rio Oso, Not modeled PG&E HIGGNS_1_COMBIE 0.00 Sierra South of Palermo, Market Energy Only South of Table Mountain Drum-Rio Oso, South of Rio Oso, Not modeled PG&E HIGGNS_7_QFUNTS 0.23 Sierra South of Palermo, QF/Selfgen Aug NQC South of Table Mountain Drum-Rio Oso, Not modeled PG&E KANAKA_1_UNIT 0.00 Sierra South of Table MUNI Aug NQC Mountain Drum-Rio Oso, PG&E KELYRG_6_UNIT 31834 KELLYRDG 9.11 11.00 1 Sierra South of Table Aug NQC MUNI Mountain Pease, South of Not modeled PG&E LIVEOK_6_SOLAR 0.51 Sierra Market Table Mountain Aug NQC South of Rio Oso, South of Palermo, PG&E LODIEC_2_PL1X2 38124 LODI ST1 18 95.82 1 Sierra MUNI South of Table Mountain South of Rio Oso, South of Palermo, PG&E LODIEC_2_PL1X2 38123 LODI CT1 18 184.18 1 Sierra MUNI South of Table Mountain South of Rio Oso, South of Palermo, PG&E MDFKRL_2_PROJCT 32456 MIDLFORK 13.8 63.94 1 Sierra Aug NQC MUNI South of Table Mountain South of Rio Oso, South of Palermo, PG&E MDFKRL_2_PROJCT 32458 RALSTON 13.8 82.13 1 Sierra Aug NQC MUNI South of Table Mountain South of Rio Oso, South of Palermo, PG&E MDFKRL_2_PROJCT 32456 MIDLFORK 13.8 63.94 2 Sierra Aug NQC MUNI South of Table Mountain South of Table PG&E NAROW1_2_UNIT 32466 NARROWS1 9.1 12.00 1 Sierra Aug NQC Market Mountain South of Table PG&E NAROW2_2_UNIT 32468 NARROWS2 9.1 28.51 1 Sierra Aug NQC MUNI Mountain

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Placer, Drum-Rio Oso, South of Rio PG&E NWCSTL_7_UNIT 1 32460 NEWCSTLE 13.2 12.00 1 Sierra Oso, South of Aug NQC Market Palermo, South of Table Mountain Drum-Rio Oso, PG&E OROVIL_6_UNIT 31888 OROVLLE 9.11 7.50 1 Sierra South of Table Aug NQC Market Mountain Weimer, Drum-Rio Oso, South of PG&E OXBOW_6_DRUM 32484 OXBOW F 9.11 6.00 1 Sierra Aug NQC MUNI Palermo, South of Table Mountain Placerville, South of Rio Oso, South PG&E PLACVL_1_CHILIB 32510 CHILIBAR 4.2 0.00 1 Sierra Aug NQC Market of Palermo, South of Table Mountain Placerville, South of Rio Oso, South Not modeled PG&E PLACVL_1_RCKCRE 2.18 Sierra Market of Palermo, South Aug NQC of Table Mountain Drum-Rio Oso, South of Rio Oso, Not modeled PG&E PLSNTG_7_LNCLND 32408 PLSNT GR 60 3.26 Sierra South of Palermo, Market Aug NQC South of Table Mountain South of Palermo, PG&E POEPH_7_UNIT 1 31790 POE 1 13.8 60.00 1 Sierra South of Table Aug NQC Market Mountain South of Palermo, PG&E POEPH_7_UNIT 2 31792 POE 2 13.8 60.00 1 Sierra South of Table Aug NQC Market Mountain South of Palermo, PG&E RCKCRK_7_UNIT 1 31786 ROCK CK1 13.8 57.00 1 Sierra South of Table Aug NQC Market Mountain South of Palermo, PG&E RCKCRK_7_UNIT 2 31788 ROCK CK2 13.8 56.90 1 Sierra South of Table Aug NQC Market Mountain Drum-Rio Oso, South of Palermo, Not modeled PG&E RIOOSO_1_QF 0.93 Sierra QF/Selfgen South of Table Aug NQC Mountain Weimer, Drum-Rio PG&E ROLLIN_6_UNIT 32476 ROLLINSF 9.11 13.50 1 Sierra Aug NQC MUNI Oso, South of

151 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Palermo, South of Table Mountain

Drum-Rio Oso, PG&E SLYCRK_1_UNIT 1 31832 SLY.CR. 9.11 13.00 1 Sierra South of Table Aug NQC Market Mountain Drum-Rio Oso, South of Palermo, PG&E SPAULD_6_UNIT 3 32472 SPAULDG 9.11 6.50 3 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E SPAULD_6_UNIT12 32472 SPAULDG 9.11 7.00 1 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Palermo, PG&E SPAULD_6_UNIT12 32472 SPAULDG 9.11 4.40 2 Sierra Aug NQC Market South of Table Mountain Drum-Rio Oso, South of Rio Oso, PG&E SPI LI_2_UNIT 1 32498 SPILINCF 12.5 12.99 1 Sierra South of Palermo, Aug NQC Net Seller South of Table Mountain South of Rio Oso, South of Palermo, PG&E STIGCT_2_LODI 38114 Stig CC 13.8 49.50 1 Sierra MUNI South of Table Mountain Drum-Rio Oso, South of Rio Oso, PG&E ULTRCK_2_UNIT 32500 ULTR RCK 9.11 22.83 1 Sierra South of Palermo, Aug NQC Market South of Table Mountain Drum-Rio Oso, PG&E WDLEAF_7_UNIT 1 31794 WOODLEAF 13.8 60.00 1 Sierra South of Table Aug NQC MUNI Mountain South of Table Not modeled PG&E WHEATL_6_LNDFIL 32350 WHEATLND 60 3.20 Sierra Market Mountain Aug NQC Placer, Drum-Rio Oso, South of Rio PG&E WISE_1_UNIT 1 32512 WISE 12 14.50 1 Sierra Oso, South of Aug NQC Market Palermo, South of Table Mountain

152 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Placer, Drum-Rio Oso, South of Rio PG&E WISE_1_UNIT 2 32512 WISE 12 3.20 1 Sierra Oso, South of Aug NQC Market Palermo, South of Table Mountain Pease, Drum-Rio PG&E YUBACT_1_SUNSWT 32494 YUBA CTY 9.11 49.97 1 Sierra Oso, South of Aug NQC Net Seller Table Mountain Pease, Drum-Rio PG&E YUBACT_6_UNITA1 32496 YCEC 13.8 47.60 1 Sierra Oso, South of Market Table Mountain Drum-Rio Oso, South of Palermo, No NQC - PG&E ZZ_NA 32162 RIV.DLTA 9.11 0.00 1 Sierra QF/Selfgen South of Table hist. data Mountain Drum-Rio Oso, South of Palermo, No NQC - PG&E ZZ_UCDAVS_1_UNIT 32166 UC DAVIS 9.11 0.00 RN Sierra QF/Selfgen South of Table hist. data Mountain Drum-Rio Oso, South of Palermo, No NQC - PG&E ZZZ_New Unit 365510 Q653F 0.48 4.92 1 Sierra Market South of Table est. data Mountain Drum-Rio Oso, ZZZZZ_PACORO_6_UNIT 31890 PO POWER 9.11 0.00 1 Sierra South of Table Retired QF/Selfgen PG&E Mountain Drum-Rio Oso, ZZZZZ_PACORO_6_UNIT 31890 PO POWER 9.11 0.00 2 Sierra South of Table Retired QF/Selfgen PG&E Mountain Tesla-Bellota, PG&E BEARDS_7_UNIT 1 34074 BEARDSLY 6.9 8.36 1 Stockton Aug NQC MUNI Stanislaus PG&E CAMCHE_1_PL1X3 33850 CAMANCHE 4.2 0.20 1 Stockton Tesla-Bellota Aug NQC MUNI PG&E CAMCHE_1_PL1X3 33850 CAMANCHE 4.2 0.20 2 Stockton Tesla-Bellota Aug NQC MUNI PG&E CAMCHE_1_PL1X3 33850 CAMANCHE 4.2 0.20 3 Stockton Tesla-Bellota Aug NQC MUNI STCKNBIOMA PG&E COGNAT_1_UNIT 33818 13.8 42.33 1 Stockton Weber Aug NQC Net Seller SS PG&E CRWCKS_1_SOLAR1 34051 Q539 34.5 0.00 1 Stockton Tesla-Bellota Energy Only Market Tesla-Bellota, PG&E DONNLS_7_UNIT 34058 DONNELLS 13.8 72.00 1 Stockton Aug NQC MUNI Stanislaus Tesla-Bellota, Not Modeled PG&E FROGTN_1_UTICAA 0.49 Stockton Market Stanislaus Aug NQC

153 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Tesla-Bellota, Not modeled PG&E FROGTN_7_UTICA 0.00 Stockton Market Stanislaus Energy Only Not modeled PG&E LOCKFD_1_BEARCK 0.62 Stockton Tesla-Bellota Market Energy Only Not modeled PG&E LOCKFD_1_KSOLAR 0.41 Stockton Tesla-Bellota Market Energy Only PG&E LODI25_2_UNIT 1 38120 LODI25CT 9.11 23.80 1 Stockton Lockeford MUNI Not modeled PG&E MANTEC_1_ML1SR1 0.00 Stockton Tesla-Bellota Market Energy Only Tesla-Bellota, Not modeled PG&E PEORIA_1_SOLAR 0.62 Stockton Market Stanislaus Aug NQC Tesla-Bellota, Not modeled PG&E PHOENX_1_UNIT 0.90 Stockton Market Stanislaus Aug NQC PG&E SCHLTE_1_PL1X3 33805 GWFTRCY1 13.8 88.55 1 Stockton Tesla-Bellota Market PG&E SCHLTE_1_PL1X3 33807 GWFTRCY2 13.8 88.55 1 Stockton Tesla-Bellota Market PG&E SCHLTE_1_PL1X3 33811 GWFTRCY3 13.8 142.70 1 Stockton Tesla-Bellota Market PG&E SMPRIP_1_SMPSON 33810 SP CMPNY 13.8 46.05 1 Stockton Tesla-Bellota Aug NQC Market Tesla-Bellota, PG&E SNDBAR_7_UNIT 1 34060 SANDBAR 13.8 7.06 1 Stockton Aug NQC MUNI Stanislaus Tesla-Bellota, PG&E SPIFBD_1_PL1X2 34055 SPISONORA 13.8 2.32 1 Stockton Aug NQC Market Stanislaus Tesla-Bellota, PG&E SPRGAP_1_UNIT 1 34078 SPRNG GP 6 7.00 1 Stockton Aug NQC Market Stanislaus Tesla-Bellota, PG&E STANIS_7_UNIT 1 34062 STANISLS 13.8 91.00 1 Stockton Aug NQC Market Stanislaus PG&E STNRES_1_UNIT 34056 STNSLSRP 13.8 19.27 1 Stockton Tesla-Bellota Aug NQC Net Seller PG&E THMENG_1_UNIT 1 33806 TH.E.DV. 13.8 4.89 1 Stockton Tesla-Bellota Aug NQC Net Seller PG&E TULLCK_7_UNITS 34076 TULLOCH 6.9 4.79 1 Stockton Tesla-Bellota Aug NQC MUNI PG&E TULLCK_7_UNITS 34076 TULLOCH 6.9 5.39 2 Stockton Tesla-Bellota Aug NQC MUNI PG&E TULLCK_7_UNITS 34076 TULLOCH 6.9 3.54 3 Stockton Tesla-Bellota Aug NQC MUNI Tesla-Bellota, PG&E ULTPCH_1_UNIT 1 34050 CH.STN. 13.8 16.19 1 Stockton Aug NQC QF/Selfgen Stanislaus Tesla-Bellota, Not modeled PG&E VLYHOM_7_SSJID 0.57 Stockton MUNI Stanislaus Aug NQC Not modeled PG&E WEBER_6_FORWRD 4.20 Stockton Weber Market Aug NQC No NQC - PG&E ZZ_NA 33830 GEN.MILL 9.11 0.00 1 Stockton Lockeford QF/Selfgen hist. data

154 / 226 Appendix A - List of physical resources by PTO, local area and market ID

No NQC - PG&E ZZ_NA 33687 STKTN WW 60 1.50 1 Stockton Weber QF/Selfgen hist. data No NQC - PG&E ZZ_NA 33821 PAC_ETH 12.5 0.00 RN Stockton Weber QF/Selfgen hist. data ZZZZZ_STOKCG_1_UNIT 33814 INGREDION 12.5 0.00 RN Stockton Tesla-Bellota Retired QF/Selfgen PG&E 1 ZZZZZZZ_SANJOA_1_UNI 33808 SJ COGEN 13.8 0.00 1 Stockton Tesla-Bellota Retired QF/Selfgen PG&E T 1 SCE ACACIA_6_SOLAR 29878 ACACIA_G 0.48 8.20 EQ BC/Ventura Big Creek Energy Only Market SCE ALAMO_6_UNIT 25653 ALAMO SC 13.8 15.07 1 BC/Ventura Big Creek Aug NQC MUNI Big Creek, Rector, SCE BIGCRK_2_EXESWD 24323 PORTAL 4.8 9.45 1 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24306 B CRK1-1 7.2 19.58 1 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24311 B CRK3-1 13.8 34.44 1 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24308 B CRK2-1 13.8 49.99 1 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24317 MAMOTH1G 13.8 92.02 1 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24306 B CRK1-1 7.2 21.26 2 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24311 B CRK3-1 13.8 33.46 2 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24308 B CRK2-1 13.8 51.18 2 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24318 MAMOTH2G 13.8 92.02 2 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24309 B CRK2-2 7.2 18.40 3 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24307 B CRK1-2 13.8 21.26 3 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24312 B CRK3-2 13.8 34.44 3 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24309 B CRK2-2 7.2 19.39 4 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24307 B CRK1-2 13.8 30.71 4 BC/Ventura Aug NQC Market Vestal

155 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Big Creek, Rector, SCE BIGCRK_2_EXESWD 24312 B CRK3-2 13.8 35.43 4 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24310 B CRK2-3 7.2 16.73 5 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24313 B CRK3-3 13.8 35.92 5 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24310 B CRK2-3 7.2 18.21 6 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24314 B CRK 4 11.5 49.60 41 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24314 B CRK 4 11.5 49.80 42 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24315 B CRK 8 13.8 24.01 81 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE BIGCRK_2_EXESWD 24315 B CRK 8 13.8 43.30 82 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, Not modeled SCE BIGCRK_7_DAM7 0.00 BC/Ventura Market Vestal Energy Only Big Creek, Rector, Not modeled SCE BIGCRK_7_MAMRES 0.00 BC/Ventura Market Vestal Energy Only SCE BIGSKY_2_BSKSR6 29742 BSKY G BC 0.42 8.20 1 BC/Ventura Big Creek Aug NQC Market BSKY G SCE BIGSKY_2_BSKSR7 29703 0.42 8.20 1 BC/Ventura Big Creek Aug NQC Market WABS

SCE BIGSKY_2_BSKSR8 29724 BSKY G ABSR 0.38 8.20 1 BC/Ventura Big Creek Aug NQC Market

SCE BIGSKY_2_SOLAR1 29727 BSKY G SMR 0.42 8.20 1 BC/Ventura Big Creek Aug NQC Market

SCE BIGSKY_2_SOLAR2 29701 BSKY_G_ESC 0.42 34.02 1 BC/Ventura Big Creek Aug NQC Market

SCE BIGSKY_2_SOLAR3 29745 BSKY_G_BD 0.42 8.20 1 BC/Ventura Big Creek Aug NQC Market SCE BIGSKY_2_SOLAR4 29736 BSKY_G_BA 0.42 17.07 1 BC/Ventura Big Creek Aug NQC Market SCE BIGSKY_2_SOLAR5 29739 BSKY_G_BB 0.42 2.05 1 BC/Ventura Big Creek Aug NQC Market BSKY_G_SOL SCE BIGSKY_2_SOLAR6 29730 0.42 34.85 1 BC/Ventura Big Creek Aug NQC Market V BSKY_G_ADS SCE BIGSKY_2_SOLAR7 29733 0.42 20.50 1 BC/Ventura Big Creek Aug NQC Market R SCE CEDUCR_2_SOLAR1 25049 DUCOR1 0.39 0.00 EQ BC/Ventura Big Creek, Vestal Energy Only Market SCE CEDUCR_2_SOLAR2 25052 DUCOR2 0.39 0.00 EQ BC/Ventura Big Creek, Vestal Energy Only Market SCE CEDUCR_2_SOLAR3 25055 DUCOR3 0.39 0.00 EQ BC/Ventura Big Creek, Vestal Energy Only Market

156 / 226 Appendix A - List of physical resources by PTO, local area and market ID

SCE CEDUCR_2_SOLAR4 25058 DUCOR4 0.39 0.00 EQ BC/Ventura Big Creek, Vestal Energy Only Market SCE DELSUR_6_CREST 0.00 BC/Ventura Big Creek Energy Only Market Not modeled SCE DELSUR_6_DRYFRB 2.05 BC/Ventura Big Creek Market Aug NQC Not modeled SCE DELSUR_6_SOLAR1 2.67 BC/Ventura Big Creek Market Aug NQC Big Creek, Rector, SCE EASTWD_7_UNIT 24319 EASTWOOD 13.8 199.00 1 BC/Ventura Market Vestal SCE EDMONS_2_NSPIN 25605 EDMON1AP 14.4 16.86 1 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25606 EDMON2AP 14.4 16.86 2 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25607 EDMON3AP 14.4 16.86 3 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25607 EDMON3AP 14.4 16.86 4 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25608 EDMON4AP 14.4 16.86 5 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25608 EDMON4AP 14.4 16.86 6 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25609 EDMON5AP 14.4 16.86 7 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25609 EDMON5AP 14.4 16.86 8 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25610 EDMON6AP 14.4 16.86 9 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25610 EDMON6AP 14.4 16.86 10 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25611 EDMON7AP 14.4 16.85 11 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25611 EDMON7AP 14.4 16.85 12 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25612 EDMON8AP 14.4 16.85 13 BC/Ventura Big Creek Pumps MUNI SCE EDMONS_2_NSPIN 25612 EDMON8AP 14.4 16.85 14 BC/Ventura Big Creek Pumps MUNI SCE GLDFGR_6_SOLAR1 25079 PRIDE B G 0.64 8.20 1 BC/Ventura Big Creek Aug NQC Market SCE GLDFGR_6_SOLAR2 25169 PRIDE C G 0.64 4.67 1 BC/Ventura Big Creek Aug NQC Market SCE GLOW_6_SOLAR 29896 APPINV 0.42 0.00 EQ BC/Ventura Big Creek Energy Only Market Ventura, S.Clara, Not modeled SCE GOLETA_2_QF 24057 GOLETA 66 0.05 BC/Ventura QF/Selfgen Moorpark Aug NQC Retirement requested Ventura, S.Clara, SCE GOLETA_6_ELLWOD 29004 ELLWOOD 13.8 0.00 1 BC/Ventura effective Market Moorpark date January 1, 2019 Aug NQC - Ventura, S.Clara, SCE GOLETA_6_EXGEN 24362 EXGEN2 13.8 4.10 G1 BC/Ventura Currently out QF/Selfgen Moorpark of service

157 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Aug NQC - Ventura, S.Clara, SCE GOLETA_6_EXGEN 24326 EXGEN1 13.8 2.83 S1 BC/Ventura Currently out QF/Selfgen Moorpark of service Ventura, S.Clara, Not modeled SCE GOLETA_6_GAVOTA 24057 GOLETA 66 0.26 BC/Ventura Market Moorpark Aug NQC Ventura, S.Clara, Not modeled SCE GOLETA_6_TAJIGS 24057 GOLETA 66 2.84 BC/Ventura Market Moorpark Aug NQC SCE LEBECS_2_UNITS 29051 PSTRIAG1 18 165.58 G1 BC/Ventura Big Creek Aug NQC Market SCE LEBECS_2_UNITS 29052 PSTRIAG2 18 165.58 G2 BC/Ventura Big Creek Aug NQC Market SCE LEBECS_2_UNITS 29054 PSTRIAG3 18 165.58 G3 BC/Ventura Big Creek Aug NQC Market SCE LEBECS_2_UNITS 29053 PSTRIAS1 18 170.45 S1 BC/Ventura Big Creek Aug NQC Market SCE LEBECS_2_UNITS 29055 PSTRIAS2 18 82.79 S2 BC/Ventura Big Creek Aug NQC Market Not modeled SCE LITLRK_6_SEPV01 0.00 BC/Ventura Big Creek Market Energy Only Not modeled SCE LITLRK_6_SOLAR1 2.05 BC/Ventura Big Creek Market Aug NQC Not modeled SCE LITLRK_6_SOLAR2 0.82 BC/Ventura Big Creek Market Aug NQC Not modeled SCE LITLRK_6_SOLAR4 1.23 BC/Ventura Big Creek Market Aug NQC Not modeled SCE LNCSTR_6_CREST 0.00 BC/Ventura Big Creek Market Energy Only Ventura, S.Clara, SCE MNDALY_6_MCGRTH 29306 MCGPKGEN 13.8 47.20 1 BC/Ventura Market Moorpark SCE MOORPK_2_CALABS 25081 WDT251 13.8 5.40 EQ BC/Ventura Ventura, Moorpark Aug NQC Market Ventura, S.Clara, SCE MOORPK_6_QF 29952 CAMGEN 13.8 26.42 D1 BC/Ventura Aug NQC Market Moorpark Not modeled SCE MOORPK_7_UNITA1 24098 MOORPARK 66 2.12 BC/Ventura Ventura, Moorpark Market Aug NQC SCE NEENCH_6_SOLAR 29900 ALPINE_G 0.48 27.06 EQ BC/Ventura Big Creek Aug NQC Market Not modeled SCE OASIS_6_CREST 0.00 BC/Ventura Big Creek Market Energy Only Not modeled SCE OASIS_6_SOLAR1 25095 SOLARISG2 0.2 0.00 EQ BC/Ventura Big Creek Market Energy Only SCE OASIS_6_SOLAR2 25075 SOLARISG 0.2 8.20 EQ BC/Ventura Big Creek Aug NQC Market Not modeled SCE OASIS_6_SOLAR3 0.00 BC/Ventura Big Creek Market Energy Only SCE OMAR_2_UNIT 1 24102 OMAR 1G 13.8 72.80 1 BC/Ventura Big Creek Net Seller

158 / 226 Appendix A - List of physical resources by PTO, local area and market ID

SCE OMAR_2_UNIT 2 24103 OMAR 2G 13.8 74.00 2 BC/Ventura Big Creek Net Seller SCE OMAR_2_UNIT 3 24104 OMAR 3G 13.8 75.90 3 BC/Ventura Big Creek Net Seller SCE OMAR_2_UNIT 4 24105 OMAR 4G 13.8 81.44 4 BC/Ventura Big Creek Net Seller Retirement requested SCE ORMOND_7_UNIT 1 24107 ORMOND1G 26 0.00 1 BC/Ventura Ventura, Moorpark effective Market date October 1, 2018 Retirement requested SCE ORMOND_7_UNIT 2 24108 ORMOND2G 26 0.00 2 BC/Ventura Ventura, Moorpark effective Market date October 1, 2018 SCE OSO_6_NSPIN 25614 OSO A P 13.2 2.25 1 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25614 OSO A P 13.2 2.25 2 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25614 OSO A P 13.2 2.25 3 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25614 OSO A P 13.2 2.25 4 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25615 OSO B P 13.2 2.25 5 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25615 OSO B P 13.2 2.25 6 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25615 OSO B P 13.2 2.25 7 BC/Ventura Big Creek Pumps MUNI SCE OSO_6_NSPIN 25615 OSO B P 13.2 2.25 8 BC/Ventura Big Creek Pumps MUNI SCE PANDOL_6_UNIT 24113 PANDOL 13.8 23.32 1 BC/Ventura Big Creek, Vestal Aug NQC Market SCE PANDOL_6_UNIT 24113 PANDOL 13.8 23.32 2 BC/Ventura Big Creek, Vestal Aug NQC Market SSOLAR)GR SCE PLAINV_6_BSOLAR 29917 0.8 0.00 1 BC/Ventura Big Creek Energy Only Market WKS SCE PLAINV_6_DSOLAR 29914 WADR_PV 0.42 4.10 1 BC/Ventura Big Creek Aug NQC Market SCE PLAINV_6_NLRSR1 29921 NLR_INVTR 0.42 0.00 1 BC/Ventura Big Creek Aug NQC Market SCE PLAINV_6_SOLAR3 25089 CNTRL ANT G 0.42 0.00 1 BC/Ventura Big Creek Energy Only Market SIRA SOLAR SCE PLAINV_6_SOLARC 25086 0.8 0.00 1 BC/Ventura Big Creek Energy Only Market G Not modeled SCE PMDLET_6_SOLAR1 4.10 BC/Ventura Big Creek Market Aug NQC Big Creek, Rector, Not modeled SCE RECTOR_2_CREST 24212 RECTOR 66 0.00 BC/Ventura Market Vestal Aug NQC Big Creek, Rector, SCE RECTOR_2_KAWEAH 24370 KAWGEN 13.8 0.03 1 BC/Ventura Aug NQC Market Vestal Big Creek, Rector, SCE RECTOR_2_KAWH 1 24370 KAWGEN 13.8 0.19 1 BC/Ventura Aug NQC Market Vestal

159 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Big Creek, Rector, Not modeled SCE RECTOR_2_QF 24212 RECTOR 66 0.07 BC/Ventura QF/Selfgen Vestal Aug NQC Big Creek, Rector, SCE RECTOR_7_TULARE 24212 RECTOR 66 0.00 BC/Ventura Not modeled Market Vestal Not modeled SCE REDMAN_2_SOLAR 1.54 BC/Ventura Big Creek Market Aug NQC Not modeled SCE ROSMND_6_SOLAR 1.23 BC/Ventura Big Creek Market Aug NQC SCE RSMSLR_6_SOLAR1 29984 DAWNGEN 0.8 8.20 EQ BC/Ventura Big Creek Aug NQC Market SCE RSMSLR_6_SOLAR2 29888 TWILGHTG 0.8 8.20 EQ BC/Ventura Big Creek Aug NQC Market Not modeled SCE SAUGUS_2_TOLAND 24135 SAUGUS 66 0.00 BC/Ventura Big Creek Market Energy Only Not modeled SCE SAUGUS_6_MWDFTH 24135 SAUGUS 66 7.40 BC/Ventura Big Creek MUNI Aug NQC SCE SAUGUS_6_PTCHGN 24118 PITCHGEN 13.8 19.91 D1 BC/Ventura Big Creek Aug NQC MUNI Not modeled SCE SAUGUS_6_QF 24135 SAUGUS 66 0.62 BC/Ventura Big Creek QF/Selfgen Aug NQC Not modeled SCE SAUGUS_7_CHIQCN 24135 SAUGUS 66 5.61 BC/Ventura Big Creek Market Aug NQC Not modeled SCE SAUGUS_7_LOPEZ 24135 SAUGUS 66 5.34 BC/Ventura Big Creek QF/Selfgen Aug NQC Not modeled SCE SHUTLE_6_CREST 0.00 BC/Ventura Big Creek Market Energy Only Ventura, S.Clara, SCE SNCLRA_2_HOWLNG 25080 GFID8045 13.8 7.63 EQ BC/Ventura Aug NQC Market Moorpark Ventura, S.Clara, Not modeled SCE SNCLRA_2_SPRHYD 0.38 BC/Ventura Market Moorpark Aug NQC Ventura, S.Clara, SCE SNCLRA_2_UNIT1 24159 WILLAMET 3.8 19.03 D1 BC/Ventura Aug NQC Market Moorpark Ventura, S.Clara, SCE SNCLRA_6_OXGEN 24110 OXGEN 13.8 34.10 D1 BC/Ventura Aug NQC QF/Selfgen Moorpark Ventura, S.Clara, SCE SNCLRA_6_PROCGN 24119 PROCGEN 13.8 45.74 D1 BC/Ventura Aug NQC Market Moorpark Ventura, S.Clara, Not modeled SCE SNCLRA_6_QF 0.00 BC/Ventura QF/Selfgen Moorpark Aug NQC Big Creek, Rector, Not modeled SCE SPRGVL_2_CREST 24215 SPRINGVL 66 0.00 BC/Ventura Market Vestal Energy Only Big Creek, Rector, Not modeled SCE SPRGVL_2_QF 24215 SPRINGVL 66 0.12 BC/Ventura QF/Selfgen Vestal Aug NQC

160 / 226 Appendix A - List of physical resources by PTO, local area and market ID

Big Creek, Rector, Not modeled SCE SPRGVL_2_TULE 24215 SPRINGVL 66 0.00 BC/Ventura Market Vestal Aug NQC Big Creek, Rector, Not modeled SCE SPRGVL_2_TULESC 24215 SPRINGVL 66 0.03 BC/Ventura Market Vestal Aug NQC SCE SUNSHN_2_LNDFL 29954 WDT273 13.7 3.33 1 BC/Ventura Big Creek Aug NQC Market SCE SUNSHN_2_LNDFL 29954 WDT273 13.7 3.33 2 BC/Ventura Big Creek Aug NQC Market SCE SUNSHN_2_LNDFL 29954 WDT273 13.7 3.33 3 BC/Ventura Big Creek Aug NQC Market SCE SUNSHN_2_LNDFL 29954 WDT273 13.7 3.33 4 BC/Ventura Big Creek Aug NQC Market SCE SUNSHN_2_LNDFL 29954 WDT273 13.7 3.33 5 BC/Ventura Big Creek Aug NQC Market SCE SYCAMR_2_UNIT 1 24143 SYCCYN1G 13.8 85.00 1 BC/Ventura Big Creek Aug NQC Net Seller SCE SYCAMR_2_UNIT 2 24144 SYCCYN2G 13.8 85.00 2 BC/Ventura Big Creek Aug NQC Net Seller SCE SYCAMR_2_UNIT 3 24145 SYCCYN3G 13.8 85.00 3 BC/Ventura Big Creek Aug NQC Net Seller SCE SYCAMR_2_UNIT 4 24146 SYCCYN4G 13.8 85.00 4 BC/Ventura Big Creek Aug NQC Net Seller SCE TENGEN_2_PL1X2 24148 TENNGEN1 13.8 18.57 D1 BC/Ventura Big Creek Aug NQC Net Seller SCE TENGEN_2_PL1X2 24149 TENNGEN2 13.8 18.57 D2 BC/Ventura Big Creek Aug NQC Net Seller SCE VESTAL_2_KERN 24372 KR 3-1 11 0.24 1 BC/Ventura Big Creek, Vestal Aug NQC QF/Selfgen SCE VESTAL_2_KERN 24373 KR 3-2 11 0.23 2 BC/Ventura Big Creek, Vestal Aug NQC QF/Selfgen Not modeled SCE VESTAL_2_RTS042 0.00 BC/Ventura Big Creek, Vestal Market Energy Only SCE VESTAL_2_SOLAR1 25066 TULRESLR 0.39 8.20 1 BC/Ventura Big Creek, Vestal Aug NQC Market SCE VESTAL_2_SOLAR2 25067 TULRESLR 0.39 1.78 1 BC/Ventura Big Creek, Vestal Aug NQC Market SCE VESTAL_2_SOLAR2 25068 TULRESLR 0.36 3.96 1 BC/Ventura Big Creek, Vestal Aug NQC Market Not modeled SCE VESTAL_2_UNIT1 4.39 BC/Ventura Big Creek, Vestal Market Aug NQC SCE VESTAL_2_WELLHD 24116 WELLGEN 13.8 49.00 1 BC/Ventura Big Creek, Vestal Market SCE VESTAL_6_QF 29008 LAKEGEN 13.8 1.04 1 BC/Ventura Big Creek, Vestal Aug NQC QF/Selfgen SCE WARNE_2_UNIT 25651 WARNE1 13.8 38.00 1 BC/Ventura Big Creek Aug NQC MUNI SCE WARNE_2_UNIT 25652 WARNE2 13.8 38.00 2 BC/Ventura Big Creek Aug NQC MUNI No NQC - SCE ZZ_NA 24422 PALMDALE 66 0.00 1 BC/Ventura Big Creek Market hist. data Ventura, S.Clara, No NQC - SCE ZZ_NA 24340 CHARMIN 13.8 2.80 1 BC/Ventura QF/Selfgen Moorpark hist. data

SCE ZZ_VESTAL_6_ULTRGN 24150 ULTRAGEN 13.8 0.00 1 BC/Ventura Big Creek, Vestal Aug NQC QF/Selfgen

No NQC - SCE ZZZ_New Unit 25171 PRIDE A G 0.64 4.10 1 BC/Ventura Big Creek Market est. data

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No NQC - SCE ZZZ_New Unit 25170 PRIDE A G2 0.64 4.10 1 BC/Ventura Big Creek Market est. data ZZZZZ_APPGEN_6_UNIT SCE 24009 APPGEN1G 13.8 0.00 1 BC/Ventura Big Creek Retired Market 1 ZZZZZ_APPGEN_6_UNIT SCE 24010 APPGEN2G 13.8 0.00 2 BC/Ventura Big Creek Retired Market 1 ZZZZZ_APPGEN_6_UNIT SCE 24361 APPGEN3G 13.8 0.00 3 BC/Ventura Big Creek Retired Market 1 ZZZZZ_MNDALY_7_UNIT Ventura, S.Clara, SCE 24089 MANDLY1G 13.8 0.00 1 BC/Ventura Retired Market 1 Moorpark ZZZZZ_MNDALY_7_UNIT Ventura, S.Clara, SCE 24090 MANDLY2G 13.8 0.00 2 BC/Ventura Retired Market 2 Moorpark ZZZZZ_MNDALY_7_UNIT Ventura, S.Clara, SCE 24222 MANDLY3G 16 0.00 3 BC/Ventura Retired Market 3 Moorpark Replaced by ZZZZZ_SNCLRA_6_WILL Ventura, S.Clara, SCE 24159 WILLAMET 13.8 0.00 D1 BC/Ventura SNCLRA_2_ QF/Selfgen MT Moorpark UNIT1 Retired by SCE ALAMIT_7_UNIT 1 24001 ALAMT1 G 18 0.00 1 LA Basin Western Market 2021 Retired by SCE ALAMIT_7_UNIT 2 24002 ALAMT2 G 18 0.00 2 LA Basin Western Market 2021 Retired by SCE ALAMIT_7_UNIT 3 24003 ALAMT3 G 18 0.00 3 LA Basin Western Market 2021 Retired by SCE ALAMIT_7_UNIT 4 24004 ALAMT4 G 18 0.00 4 LA Basin Western Market 2021 Retired by SCE ALAMIT_7_UNIT 5 24005 ALAMT5 G 20 0.00 5 LA Basin Western Market 2021 Retired by SCE ALAMIT_7_UNIT 6 24161 ALAMT6 G 20 0.00 6 LA Basin Western Market 2021 Eastern, Valley- SCE ALTWD_1_QF 25635 ALTWIND 115 6.23 Q1 LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- SCE ALTWD_1_QF 25635 ALTWIND 115 6.23 Q2 LA Basin Aug NQC QF/Selfgen Devers SCE ANAHM_2_CANYN1 25211 CanyonGT 1 13.8 49.40 1 LA Basin Western MUNI SCE ANAHM_2_CANYN2 25212 CanyonGT 2 13.8 48.00 2 LA Basin Western MUNI SCE ANAHM_2_CANYN3 25213 CanyonGT 3 13.8 48.00 3 LA Basin Western MUNI SCE ANAHM_2_CANYN4 25214 CanyonGT 4 13.8 49.40 4 LA Basin Western MUNI SCE ANAHM_7_CT 25208 DowlingCTG 13.8 40.64 1 LA Basin Western Aug NQC MUNI SCE ARCOGN_2_UNITS 24011 ARCO 1G 13.8 57.40 1 LA Basin Western Aug NQC Net Seller SCE ARCOGN_2_UNITS 24012 ARCO 2G 13.8 57.40 2 LA Basin Western Aug NQC Net Seller

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SCE ARCOGN_2_UNITS 24013 ARCO 3G 13.8 57.40 3 LA Basin Western Aug NQC Net Seller SCE ARCOGN_2_UNITS 24014 ARCO 4G 13.8 57.40 4 LA Basin Western Aug NQC Net Seller SCE ARCOGN_2_UNITS 24163 ARCO 5G 13.8 28.70 5 LA Basin Western Aug NQC Net Seller SCE ARCOGN_2_UNITS 24164 ARCO 6G 13.8 28.70 6 LA Basin Western Aug NQC Net Seller SCE BARRE_2_QF 24016 BARRE 230 0.00 LA Basin Western Not modeled QF/Selfgen SCE BARRE_6_PEAKER 29309 BARPKGEN 13.8 47.00 1 LA Basin Western Market Eastern, Valley- SCE BLAST_1_WIND 24839 BLAST 115 12.99 1 LA Basin Aug NQC Wind Devers Eastern, Valley- Not modeled SCE BUCKWD_1_NPALM1 25634 BUCKWIND 115 0.98 LA Basin Wind Devers Aug NQC Eastern, Valley- SCE BUCKWD_1_QF 25634 BUCKWIND 115 4.37 QF LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- SCE BUCKWD_7_WINTCV 25634 BUCKWIND 115 0.35 W5 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE CABZON_1_WINDA1 29290 CABAZON 33 10.87 1 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE CAPWD_1_QF 25633 CAPWIND 115 5.18 QF LA Basin Aug NQC QF/Selfgen Devers SCE CENTER_2_QF 29953 SIGGEN 13.8 18.20 D1 LA Basin Western Aug NQC QF/Selfgen SCE CENTER_2_RHONDO 24203 CENTER S 66 1.91 LA Basin Western Not modeled QF/Selfgen Not modeled SCE CENTER_2_SOLAR1 0.00 LA Basin Western Market Energy Only SCE CENTER_6_PEAKER 29308 CTRPKGEN 13.8 47.00 1 LA Basin Western Market Eastern, Eastern SCE CENTRY_6_PL1X4 25302 CLTNCTRY 13.8 36.00 1 LA Basin Aug NQC MUNI Metro SCE CHEVMN_2_UNITS 24022 CHEVGEN1 13.8 5.50 1 LA Basin Western, El Nido Aug NQC Net Seller SCE CHEVMN_2_UNITS 24023 CHEVGEN2 13.8 5.50 2 LA Basin Western, El Nido Aug NQC Net Seller WDT1250BES Eastern, Eastern SCE CHINO_2_APEBT1 25180 0.48 20.00 1 LA Basin Aug NQC Market S_ Metro Eastern, Eastern Not modeled SCE CHINO_2_JURUPA 0.00 LA Basin Market Metro Energy Only Eastern, Eastern Not modeled SCE CHINO_2_QF 0.47 LA Basin QF/Selfgen Metro Aug NQC Eastern, Eastern Not modeled SCE CHINO_2_SASOLR 0.00 LA Basin Market Metro Energy Only Eastern, Eastern SCE CHINO_2_SOLAR 0.41 LA Basin Not modeled Market Metro Eastern, Eastern Not modeled SCE CHINO_2_SOLAR2 0.00 LA Basin Market Metro Energy Only

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Eastern, Eastern SCE CHINO_6_CIMGEN 24026 CIMGEN 13.8 25.96 D1 LA Basin Aug NQC QF/Selfgen Metro Eastern, Eastern SCE CHINO_6_SMPPAP 24140 SIMPSON 13.8 22.78 D1 LA Basin Aug NQC QF/Selfgen Metro Eastern, Eastern Not modeled SCE CHINO_7_MILIKN 24024 CHINO 66 1.19 LA Basin Market Metro Aug NQC Eastern, Eastern SCE COLTON_6_AGUAM1 25303 CLTNAGUA 13.8 43.00 1 LA Basin Aug NQC MUNI Metro Eastern, Eastern Not modeled SCE CORONS_2_SOLAR 0.00 LA Basin Market Metro Energy Only Eastern, Eastern SCE CORONS_6_CLRWTR 29338 CLRWTRCT 13.8 20.72 G1 LA Basin MUNI Metro Eastern, Eastern SCE CORONS_6_CLRWTR 29340 CLRWTRST 13.8 7.28 S1 LA Basin MUNI Metro Not modeled SCE DELAMO_2_SOLAR1 0.62 LA Basin Western Market Aug NQC Not modeled SCE DELAMO_2_SOLAR2 0.72 LA Basin Western Market Aug NQC Not modeled SCE DELAMO_2_SOLAR3 0.51 LA Basin Western Market Aug NQC Not modeled SCE DELAMO_2_SOLAR4 0.53 LA Basin Western Market Aug NQC Not modeled SCE DELAMO_2_SOLAR5 0.41 LA Basin Western Market Aug NQC Not modeled SCE DELAMO_2_SOLAR6 0.82 LA Basin Western Market Aug NQC Not modeled SCE DELAMO_2_SOLRC1 0.00 LA Basin Western Market Energy Only Not modeled SCE DELAMO_2_SOLRD 0.00 LA Basin Western Market Energy Only Eastern, Valley- SCE DEVERS_1_QF 25632 TERAWND 115 8.63 QF LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- SCE DEVERS_1_QF 25639 SEAWIND 115 10.35 QF LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- Not modeled SCE DEVERS_1_SEPV05 0.00 LA Basin Market Devers Energy Only Eastern, Valley- Not modeled SCE DEVERS_1_SOLAR 0.00 LA Basin Market Devers Energy Only Eastern, Valley- Not modeled SCE DEVERS_1_SOLAR1 0.00 LA Basin Market Devers Energy Only

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Eastern, Valley- Not modeled SCE DEVERS_1_SOLAR2 0.00 LA Basin Market Devers Energy Only Eastern, Valley- Not modeled SCE DEVERS_2_DHSPG2 0.00 LA Basin Market Devers Energy Only Eastern, Eastern SCE DMDVLY_1_UNITS 25425 ESRP P2 6.9 0.00 8 LA Basin Aug NQC QF/Selfgen Metro Eastern, Eastern SCE DREWS_6_PL1X4 25301 CLTNDREW 13.8 36.00 1 LA Basin Aug NQC MUNI Metro Eastern, Eastern SCE DVLCYN_1_UNITS 25648 DVLCYN1G 13.8 50.35 1 LA Basin Aug NQC MUNI Metro Eastern, Eastern SCE DVLCYN_1_UNITS 25649 DVLCYN2G 13.8 50.35 2 LA Basin Aug NQC MUNI Metro Eastern, Eastern SCE DVLCYN_1_UNITS 25603 DVLCYN3G 13.8 67.13 3 LA Basin Aug NQC MUNI Metro Eastern, Eastern SCE DVLCYN_1_UNITS 25604 DVLCYN4G 13.8 67.13 4 LA Basin Aug NQC MUNI Metro SCE ELLIS_2_QF 24325 ORCOGEN 13.8 0.03 1 LA Basin Western Aug NQC QF/Selfgen SCE ELSEGN_2_UN1011 29904 ELSEG5GT 16.5 131.50 5 LA Basin Western, El Nido Aug NQC Market SCE ELSEGN_2_UN1011 29903 ELSEG6ST 13.8 131.50 6 LA Basin Western, El Nido Aug NQC Market SCE ELSEGN_2_UN2021 29902 ELSEG7GT 16.5 131.84 7 LA Basin Western, El Nido Aug NQC Market SCE ELSEGN_2_UN2021 29901 ELSEG8ST 13.8 131.84 8 LA Basin Western, El Nido Aug NQC Market Eastern, Eastern Not modeled SCE ETIWND_2_CHMPNE 0.00 LA Basin Market Metro Energy Only Eastern, Eastern Not modeled SCE ETIWND_2_FONTNA 24055 ETIWANDA 66 0.11 LA Basin QF/Selfgen Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS010 24055 ETIWANDA 66 0.62 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS015 24055 ETIWANDA 66 1.23 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS017 24055 ETIWANDA 66 1.44 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS018 24055 ETIWANDA 66 0.62 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS023 24055 ETIWANDA 66 1.03 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS026 24055 ETIWANDA 66 2.46 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE ETIWND_2_RTS027 24055 ETIWANDA 66 0.82 LA Basin Market Metro Aug NQC

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Eastern, Eastern Not modeled SCE ETIWND_2_SOLAR1 0.00 LA Basin Market Metro Energy Only Eastern, Eastern Not modeled SCE ETIWND_2_SOLAR2 0.00 LA Basin Market Metro Energy Only Eastern, Eastern Not modeled SCE ETIWND_2_SOLAR5 0.00 LA Basin Market Metro Energy Only Eastern, Eastern SCE ETIWND_2_UNIT1 24071 INLAND 13.8 23.36 1 LA Basin Aug NQC QF/Selfgen Metro Eastern, Eastern SCE ETIWND_6_GRPLND 29305 ETWPKGEN 13.8 46.00 1 LA Basin Market Metro Eastern, Eastern SCE ETIWND_6_MWDETI 25422 ETI MWDG 13.8 2.80 1 LA Basin Aug NQC Market Metro Eastern, Eastern Not modeled SCE ETIWND_7_MIDVLY 24055 ETIWANDA 66 1.67 LA Basin QF/Selfgen Metro Aug NQC Eastern, Valley- Not modeled SCE GARNET_1_SOLAR 24815 GARNET 115 0.00 LA Basin Market Devers Energy Only Eastern, Valley- Not modeled SCE GARNET_1_SOLAR2 24815 GARNET 115 1.64 LA Basin Market Devers Aug NQC Eastern, Valley- SCE GARNET_1_UNITS 24815 GARNET 115 2.06 G1 LA Basin Aug NQC Market Devers Eastern, Valley- SCE GARNET_1_UNITS 24815 GARNET 115 0.71 G2 LA Basin Aug NQC Market Devers Eastern, Valley- SCE GARNET_1_UNITS 24815 GARNET 115 1.61 G3 LA Basin Aug NQC Market Devers Eastern, Valley- Not modeled SCE GARNET_1_WIND 24815 GARNET 115 1.72 LA Basin Wind Devers Aug NQC Eastern, Valley- SCE GARNET_1_WINDS 24815 GARNET 115 5.96 W2 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE GARNET_1_WT3WND 24815 GARNET 115 0.00 W3 LA Basin Aug NQC Market Devers Eastern, Valley- SCE GARNET_2_HYDRO 24815 GARNET 115 0.54 QF LA Basin Aug NQC Market Devers Eastern, Valley- Not modeled SCE GARNET_2_WIND1 24815 GARNET 115 2.97 LA Basin Wind Devers Aug NQC Eastern, Valley- Not modeled SCE GARNET_2_WIND2 24815 GARNET 115 3.10 LA Basin Wind Devers Aug NQC Eastern, Valley- Not modeled SCE GARNET_2_WIND3 24815 GARNET 115 3.34 LA Basin Wind Devers Aug NQC Eastern, Valley- Not modeled SCE GARNET_2_WIND4 24815 GARNET 115 2.60 LA Basin Wind Devers Aug NQC

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Eastern, Valley- Not modeled SCE GARNET_2_WIND5 24815 GARNET 115 0.80 LA Basin Wind Devers Aug NQC GLENARM5_ SCE GLNARM_2_UNIT 5 29013 13.8 50.00 CT LA Basin Western MUNI CT GLENARM5_S SCE GLNARM_2_UNIT 5 29014 13.8 15.00 ST LA Basin Western MUNI T SCE GLNARM_7_UNIT 1 29005 PASADNA1 13.8 22.07 1 LA Basin Western MUNI SCE GLNARM_7_UNIT 2 29006 PASADNA2 13.8 22.30 1 LA Basin Western MUNI SCE GLNARM_7_UNIT 3 25042 PASADNA3 13.8 44.83 1 LA Basin Western MUNI SCE GLNARM_7_UNIT 4 25043 PASADNA4 13.8 42.42 1 LA Basin Western MUNI SCE HARBGN_7_UNITS 24062 HARBOR G 13.8 76.27 1 LA Basin Western Mothballed Market SCE HARBGN_7_UNITS 24062 HARBOR G 13.8 11.86 HP LA Basin Western Mothballed Market SCE HARBGN_7_UNITS 25510 HARBORG4 4.16 11.86 LP LA Basin Western Mothballed Market SCE HINSON_6_CARBGN 24020 CARBGEN1 13.8 14.83 1 LA Basin Western Aug NQC Market SCE HINSON_6_CARBGN 24328 CARBGEN2 13.8 14.83 1 LA Basin Western Aug NQC Market SCE HINSON_6_LBECH1 24170 LBEACH12 13.8 65.00 1 LA Basin Western Market SCE HINSON_6_LBECH2 24170 LBEACH12 13.8 65.00 2 LA Basin Western Market SCE HINSON_6_LBECH3 24171 LBEACH34 13.8 65.00 3 LA Basin Western Market SCE HINSON_6_LBECH4 24171 LBEACH34 13.8 65.00 4 LA Basin Western Market SCE HINSON_6_SERRGN 24139 SERRFGEN 13.8 28.90 D1 LA Basin Western Aug NQC QF/Selfgen Retired by SCE HNTGBH_7_UNIT 1 24066 HUNT1 G 13.8 0.00 1 LA Basin Western Market 2021 Retired by SCE HNTGBH_7_UNIT 2 24067 HUNT2 G 13.8 0.00 2 LA Basin Western Market 2021 Eastern, Valley- SCE INDIGO_1_UNIT 1 29190 WINTECX2 13.8 42.00 1 LA Basin Market Devers Eastern, Valley- SCE INDIGO_1_UNIT 2 29191 WINTECX1 13.8 42.00 1 LA Basin Market Devers Eastern, Valley- SCE INDIGO_1_UNIT 3 29180 WINTEC8 13.8 42.00 1 LA Basin Market Devers Eastern, Valley, SCE INLDEM_5_UNIT 1 29041 IEEC-G1 19.5 335.00 1 LA Basin Aug NQC Market Valley-Devers Eastern, Valley, SCE INLDEM_5_UNIT 2 29042 IEEC-G2 19.5 335.00 1 LA Basin Mothballed Market Valley-Devers SCE LACIEN_2_VENICE 24337 VENICE 13.8 0.00 1 LA Basin Western, El Nido Aug NQC MUNI Not modeled SCE LAGBEL_2_STG1 9.60 LA Basin Market Aug NQC SCE LAGBEL_6_QF 29951 REFUSE 13.8 0.29 D1 LA Basin Western Aug NQC QF/Selfgen

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SCE LGHTHP_6_ICEGEN 24070 ICEGEN 13.8 48.00 1 LA Basin Western Aug NQC QF/Selfgen Not modeled SCE MESAS_2_QF 24209 MESA CAL 66 0.00 LA Basin Western QF/Selfgen Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_CORONA 2.23 LA Basin QF/Selfgen Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_LNDFL 1.23 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_MLBBTA 10.00 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_MLBBTB 10.00 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_ONTARO 2.26 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_RTS032 0.62 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_RTS033 0.41 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE MIRLOM_2_TEMESC 1.65 LA Basin QF/Selfgen Metro Aug NQC Eastern, Eastern SCE MIRLOM_6_DELGEN 29339 DELGEN 13.8 25.93 1 LA Basin Aug NQC QF/Selfgen Metro Eastern, Eastern SCE MIRLOM_6_PEAKER 29307 MRLPKGEN 13.8 46.00 1 LA Basin Market Metro Eastern, Eastern Not modeled SCE MIRLOM_7_MWDLKM 24210 MIRALOMA 66 4.80 LA Basin MUNI Metro Aug NQC Eastern, Eastern SCE MOJAVE_1_SIPHON 25657 MJVSPHN1 13.8 4.79 1 LA Basin Aug NQC Market Metro Eastern, Eastern SCE MOJAVE_1_SIPHON 25658 MJVSPHN1 13.8 4.79 2 LA Basin Aug NQC Market Metro Eastern, Eastern SCE MOJAVE_1_SIPHON 25659 MJVSPHN1 13.8 4.79 3 LA Basin Aug NQC Market Metro Eastern, Valley- SCE MTWIND_1_UNIT 1 29060 MOUNTWND 115 11.77 S1 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE MTWIND_1_UNIT 2 29060 MOUNTWND 115 5.88 S2 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE MTWIND_1_UNIT 3 29060 MOUNTWND 115 5.95 S3 LA Basin Aug NQC Wind Devers SCE OLINDA_2_COYCRK 24211 OLINDA 66 3.13 LA Basin Western Not modeled QF/Selfgen SCE OLINDA_2_LNDFL2 29011 BREAPWR2 13.8 3.86 C1 LA Basin Western Aug NQC Market SCE OLINDA_2_LNDFL2 29011 BREAPWR2 13.8 3.86 C2 LA Basin Western Aug NQC Market

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SCE OLINDA_2_LNDFL2 29011 BREAPWR2 13.8 3.86 C3 LA Basin Western Aug NQC Market SCE OLINDA_2_LNDFL2 29011 BREAPWR2 13.8 3.86 C4 LA Basin Western Aug NQC Market SCE OLINDA_2_LNDFL2 29011 BREAPWR2 13.8 6.91 S1 LA Basin Western Aug NQC Market Not modeled SCE OLINDA_2_QF 24211 OLINDA 66 0.01 LA Basin Western QF/Selfgen Aug NQC Not modeled SCE OLINDA_7_LNDFIL 24211 OLINDA 66 0.00 LA Basin Western QF/Selfgen Aug NQC Eastern, Eastern Not modeled SCE PADUA_2_ONTARO 24111 PADUA 66 0.12 LA Basin QF/Selfgen Metro Aug NQC Eastern, Eastern Not modeled SCE PADUA_2_SOLAR1 24111 PADUA 66 0.00 LA Basin Market Metro Energy Only Eastern, Eastern Not modeled SCE PADUA_6_MWDSDM 24111 PADUA 66 5.51 LA Basin MUNI Metro Aug NQC Eastern, Eastern Not modeled SCE PADUA_6_QF 24111 PADUA 66 0.38 LA Basin QF/Selfgen Metro Aug NQC Eastern, Eastern Not modeled SCE PADUA_7_SDIMAS 24111 PADUA 66 1.05 LA Basin Market Metro Aug NQC Eastern, Valley- SCE PANSEA_1_PANARO 25640 PANAERO 115 7.95 QF LA Basin Aug NQC Wind Devers SCE PWEST_1_UNIT 24815 GARNET 115 0.56 PC LA Basin Western Aug NQC Market Retired by SCE REDOND_7_UNIT 5 24121 REDON5 G 18 0.00 5 LA Basin Western Market 2021 Retired by SCE REDOND_7_UNIT 6 24122 REDON6 G 18 0.00 6 LA Basin Western Market 2021 Retired by SCE REDOND_7_UNIT 7 24123 REDON7 G 20 0.00 7 LA Basin Western Market 2021 Retired by SCE REDOND_7_UNIT 8 24124 REDON8 G 20 0.00 8 LA Basin Western Market 2021 Eastern, Valley- SCE RENWD_1_QF 25636 RENWIND 115 1.33 Q1 LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- SCE RENWD_1_QF 25636 RENWIND 115 1.32 Q2 LA Basin Aug NQC QF/Selfgen Devers SCE RHONDO_2_QF 24213 RIOHONDO 66 0.21 DG LA Basin Western Aug NQC QF/Selfgen Not modeled SCE RHONDO_6_PUENTE 24213 RIOHONDO 66 0.00 LA Basin Western Net Seller Aug NQC Eastern, Eastern SCE RVSIDE_2_RERCU3 24299 RERC2G3 13.8 48.50 1 LA Basin MUNI Metro Eastern, Eastern SCE RVSIDE_2_RERCU4 24300 RERC2G4 13.8 48.50 1 LA Basin MUNI Metro Eastern, Eastern SCE RVSIDE_6_RERCU1 24242 RERC1G 13.8 48.35 1 LA Basin MUNI Metro

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Eastern, Eastern SCE RVSIDE_6_RERCU2 24243 RERC2G 13.8 48.50 1 LA Basin MUNI Metro Eastern, Eastern Not modeled SCE RVSIDE_6_SOLAR1 24244 SPRINGEN 13.8 3.08 LA Basin Market Metro Aug NQC Eastern, Eastern SCE RVSIDE_6_SPRING 24244 SPRINGEN 13.8 36.00 1 LA Basin Market Metro Eastern, Eastern SCE SANITR_6_UNITS 24324 SANIGEN 13.8 2.92 D1 LA Basin Aug NQC QF/Selfgen Metro SCE SANTGO_2_LNDFL1 24341 COYGEN 13.8 15.88 1 LA Basin Western Aug NQC Market SCE SANTGO_2_MABBT1 25192 WDT1406_G 0.48 2.00 1 LA Basin Western Aug NQC Market Eastern, Valley- SCE SANWD_1_QF 25646 SANWIND 115 4.11 Q1 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE SANWD_1_QF 25646 SANWIND 115 4.11 Q2 LA Basin Aug NQC Wind Devers Eastern, West of SCE SBERDO_2_PSP3 24921 MNTV-CT1 18 140.56 1 LA Basin Devers, Eastern Market Metro Eastern, West of SCE SBERDO_2_PSP3 24922 MNTV-CT2 18 140.56 1 LA Basin Devers, Eastern Market Metro Eastern, West of SCE SBERDO_2_PSP3 24923 MNTV-ST1 18 243.89 1 LA Basin Devers, Eastern Market Metro Eastern, West of SCE SBERDO_2_PSP4 24924 MNTV-CT3 18 140.56 1 LA Basin Devers, Eastern Market Metro Eastern, West of SCE SBERDO_2_PSP4 24925 MNTV-CT4 18 140.56 1 LA Basin Devers, Eastern Market Metro Eastern, West of SCE SBERDO_2_PSP4 24926 MNTV-ST2 18 243.89 1 LA Basin Devers, Eastern Market Metro Eastern, West of Not modeled SCE SBERDO_2_QF 24214 SANBRDNO 66 0.28 LA Basin Devers, Eastern QF/Selfgen Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_2_REDLND 24214 SANBRDNO 66 0.82 LA Basin Devers, Eastern Market Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_2_RTS005 24214 SANBRDNO 66 1.03 LA Basin Devers, Eastern Market Aug NQC Metro

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Eastern, West of Not modeled SCE SBERDO_2_RTS007 24214 SANBRDNO 66 1.03 LA Basin Devers, Eastern Market Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_2_RTS011 24214 SANBRDNO 66 1.44 LA Basin Devers, Eastern Market Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_2_RTS013 24214 SANBRDNO 66 1.44 LA Basin Devers, Eastern Market Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_2_RTS016 24214 SANBRDNO 66 0.62 LA Basin Devers, Eastern Market Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_2_RTS048 24214 SANBRDNO 66 0.00 LA Basin Devers, Eastern Market Energy Only Metro Eastern, West of Not modeled SCE SBERDO_2_SNTANA 24214 SANBRDNO 66 0.00 LA Basin Devers, Eastern QF/Selfgen Aug NQC Metro Eastern, West of Not modeled SCE SBERDO_6_MILLCK 24214 SANBRDNO 66 0.64 LA Basin Devers, Eastern QF/Selfgen Aug NQC Metro SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG1 29101 13.8 92.09 1 LA Basin Market 1 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG2 29102 13.8 92.40 1 LA Basin Market 2 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG3 29103 13.8 92.36 1 LA Basin Market 3 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG4 29104 13.8 91.98 1 LA Basin Market 4 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG5 29105 13.8 91.83 1 LA Basin Market 5 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG6 29106 13.8 92.16 1 LA Basin Market 6 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG7 29107 13.8 91.84 1 LA Basin Market 7 Devers SENTINEL_G Eastern, Valley- SCE SENTNL_2_CTG8 29108 13.8 91.56 1 LA Basin Market 8 Devers Eastern, Valley- SCE TIFFNY_1_DILLON 29021 WINTEC6 115 11.93 1 LA Basin Aug NQC Wind Devers Eastern, Valley- SCE TRNSWD_1_QF 25637 TRANWIND 115 10.33 QF LA Basin Aug NQC Wind Devers

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Eastern, Valley, Not modeled SCE VALLEY_5_PERRIS 24160 VALLEYSC 115 7.94 LA Basin QF/Selfgen Valley-Devers Aug NQC Eastern, Valley, Not modeled SCE VALLEY_5_REDMTN 24160 VALLEYSC 115 2.20 LA Basin QF/Selfgen Valley-Devers Aug NQC Eastern, Valley, Not modeled SCE VALLEY_5_RTS044 24160 VALLEYSC 115 3.28 LA Basin Market Valley-Devers Aug NQC Eastern, Valley, Not modeled SCE VALLEY_5_SOLAR1 24160 VALLEYSC 115 0.00 LA Basin Market Valley-Devers Energy Only Eastern, Valley, SCE VALLEY_5_SOLAR2 25082 WDT786 34.5 8.20 EQ LA Basin Aug NQC Market Valley-Devers Eastern, Valley, Not modeled SCE VALLEY_7_BADLND 24160 VALLEYSC 115 0.58 LA Basin Market Valley-Devers Aug NQC Eastern, Valley, Not modeled SCE VALLEY_7_UNITA1 24160 VALLEYSC 115 2.56 LA Basin Market Valley-Devers Aug NQC Eastern, Valley- SCE VENWD_1_WIND1 25645 VENWIND 115 2.50 Q1 LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- SCE VENWD_1_WIND2 25645 VENWIND 115 4.25 Q2 LA Basin Aug NQC QF/Selfgen Devers Eastern, Valley- SCE VENWD_1_WIND3 25645 VENWIND 115 5.05 EU LA Basin Aug NQC QF/Selfgen Devers SCE VERNON_6_GONZL1 24342 FEDGEN 13.8 5.75 1 LA Basin Western MUNI SCE VERNON_6_GONZL2 24342 FEDGEN 13.8 5.75 1 LA Basin Western MUNI SCE VERNON_6_MALBRG 24239 MALBRG1G 13.8 42.37 C1 LA Basin Western MUNI SCE VERNON_6_MALBRG 24240 MALBRG2G 13.8 42.37 C2 LA Basin Western MUNI SCE VERNON_6_MALBRG 24241 MALBRG3G 13.8 49.26 S3 LA Basin Western MUNI SCE VILLPK_2_VALLYV 24216 VILLA PK 66 4.10 DG LA Basin Western Aug NQC QF/Selfgen Not modeled SCE VILLPK_6_MWDYOR 24216 VILLA PK 66 4.20 LA Basin Western MUNI Aug NQC Eastern, Eastern SCE VISTA_2_RIALTO 24901 VSTA 230 0.41 LA Basin Energy Only Market Metro Eastern, Eastern Not modeled SCE VISTA_2_RTS028 24901 VSTA 230 1.44 LA Basin Market Metro Aug NQC Eastern, Eastern Not modeled SCE VISTA_6_QF 24902 VSTA 66 0.06 LA Basin QF/Selfgen Metro Aug NQC SCE WALCRK_2_CTG1 29201 WALCRKG1 13.8 96.00 1 LA Basin Western Market SCE WALCRK_2_CTG2 29202 WALCRKG2 13.8 96.00 1 LA Basin Western Market SCE WALCRK_2_CTG3 29203 WALCRKG3 13.8 96.00 1 LA Basin Western Market SCE WALCRK_2_CTG4 29204 WALCRKG4 13.8 96.00 1 LA Basin Western Market

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SCE WALCRK_2_CTG5 29205 WALCRKG5 13.8 96.65 1 LA Basin Western Market Not modeled SCE WALNUT_2_SOLAR 0.00 LA Basin Western Market Energy Only SCE WALNUT_6_HILLGEN 24063 HILLGEN 13.8 39.51 D1 LA Basin Western Aug NQC Net Seller Not modeled SCE WALNUT_7_WCOVCT 24157 WALNUT 66 3.45 LA Basin Western Market Aug NQC Not modeled SCE WALNUT_7_WCOVST 24157 WALNUT 66 5.51 LA Basin Western Market Aug NQC Eastern, Valley- SCE WHTWTR_1_WINDA1 29061 WHITEWTR 33 16.30 1 LA Basin Aug NQC Wind Devers No NQC - SCE ZZ_ARCOGN_2_UNITS 24018 BRIGEN 13.8 0.00 1 LA Basin Western Net Seller hist. data No NQC - SCE ZZ_HINSON_6_QF 24064 HINSON 66 0.00 1 LA Basin Western QF/Selfgen hist. data No NQC - SCE ZZ_LAFRES_6_QF 24332 PALOGEN 13.8 0.00 D1 LA Basin Western, El Nido QF/Selfgen hist. data No NQC - SCE ZZ_MOBGEN_6_UNIT 1 24094 MOBGEN 13.8 0.00 1 LA Basin Western, El Nido QF/Selfgen hist. data Eastern, Valley- No NQC - SCE ZZ_NA 29260 ALTAMSA4 115 0.00 1 LA Basin Wind Devers hist. data No NQC - SCE ZZ_NA 24329 MOBGEN2 13.8 0.00 1 LA Basin Western, El Nido QF/Selfgen hist. data No NQC - SCE ZZ_NA 24330 OUTFALL1 13.8 0.00 1 LA Basin Western, El Nido QF/Selfgen hist. data No NQC - SCE ZZ_NA 24331 OUTFALL2 13.8 0.00 1 LA Basin Western, El Nido QF/Selfgen hist. data No NQC - SCE ZZ_NA 24327 THUMSGEN 13.8 0.00 1 LA Basin Western QF/Selfgen hist. data No NQC - SCE ZZZZ_New 90000 ALMT-GT1 18 200.00 X1 LA Basin Western Market Pmax No NQC - SCE ZZZZ_New 90003 HUNT-GT1 18 202.00 X1 LA Basin Western Market Pmax No NQC - SCE ZZZZ_New 90001 ALMT-GT2 18 200.00 X2 LA Basin Western Market Pmax No NQC - SCE ZZZZ_New 90004 HUNT-GT2 18 202.00 X2 LA Basin Western Market Pmax No NQC - SCE ZZZZ_New 90002 ALMT-ST1 18 240.00 X3 LA Basin Western Market Pmax No NQC - SCE ZZZZ_New 90005 HUNT-ST1 18 240.00 X3 LA Basin Western Market Pmax

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ZZZZZ_BRDWAY_7_UNIT SCE 29007 BRODWYSC 13.8 0.00 LA Basin Western Retired MUNI 3 ZZZZZ_ETIWND_7_UNIT Eastern, Eastern SCE 24052 MTNVIST3 18 0.00 3 LA Basin Retired Market 3 Metro ZZZZZ_ETIWND_7_UNIT Eastern, Eastern SCE 24053 MTNVIST4 18 0.00 4 LA Basin Retired Market 4 Metro ZZZZZZ_ELSEGN_7_UNIT SCE 24048 ELSEG4 G 18 0.00 4 LA Basin Western, El Nido Retired Market 4 SDG&E BORDER_6_UNITA1 22149 CALPK_BD 13.8 48.00 1 SD-IV San Diego, Border Market SDG&E BREGGO_6_DEGRSL 22085 BORREGO 12.5 2.58 DG SD-IV San Diego Aug NQC Market SDG&E BREGGO_6_SOLAR 22082 BR GEN1 0.21 10.66 1 SD-IV San Diego Aug NQC Market SDG&E CBRLLO_6_PLSTP1 22092 CABRILLO 69 2.72 1 SD-IV San Diego Aug NQC Market SDG&E CCRITA_7_RPPCHF 22124 CHCARITA 138 2.00 1 SD-IV San Diego Aug NQC Market SDG&E CHILLS_1_SYCENG 22120 CARLTNHS 138 0.67 1 SD-IV San Diego Aug NQC QF/Selfgen SDG&E CHILLS_7_UNITA1 22120 CARLTNHS 138 1.52 2 SD-IV San Diego Aug NQC QF/Selfgen SDG&E CNTNLA_2_SOLAR1 23463 DW GEN3&4 0.33 51.25 1 SD-IV None Aug NQC Market SDG&E CNTNLA_2_SOLAR2 23463 DW GEN3&4 0.33 0.00 2 SD-IV None Energy Only Market SDG&E CPSTNO_7_PRMADS 22112 CAPSTRNO 138 5.65 1 SD-IV San Diego Aug NQC Market SDG&E CPVERD_2_SOLAR 23309 IV GEN3 G1 0.31 31.66 G1 SD-IV None Aug NQC Market SDG&E CPVERD_2_SOLAR 23301 IV GEN3 G2 0.31 25.33 G2 SD-IV None Aug NQC Market SDG&E CRELMN_6_RAMON1 22152 CREELMAN 69 0.82 DG SD-IV San Diego Aug NQC Market SDG&E CRELMN_6_RAMON2 22152 CREELMAN 69 2.05 DG SD-IV San Diego Aug NQC Market SDG&E CRSTWD_6_KUMYAY 22915 KUMEYAAY 0.69 13.25 1 SD-IV San Diego Aug NQC Wind SDG&E CSLR4S_2_SOLAR 23298 DW GEN1 G1 0.32 26.65 G1 SD-IV None Aug NQC Market SDG&E CSLR4S_2_SOLAR 23299 DW GEN1 G2 0.32 26.65 G2 SD-IV None Aug NQC Market SDG&E DIVSON_6_NSQF 22172 DIVISION 69 44.23 1 SD-IV San Diego Aug NQC QF/Selfgen San Diego, El SDG&E ELCAJN_6_EB1BT1 22208 EL CAJON 69 7.50 1 SD-IV Battery Cajon San Diego, El SDG&E ELCAJN_6_LM6K 23320 EC GEN2 13.8 48.10 1 SD-IV Market Cajon San Diego, El SDG&E ELCAJN_6_UNITA1 22150 EC GEN1 13.8 45.42 1 SD-IV Market Cajon ECO GEN1 SDG&E ENERSJ_2_WIND 23100 0.69 41.10 G1 SD-IV None Aug NQC Wind G1 SDG&E ESCNDO_6_EB1BT1 22256 ESCNDIDO 69 10.00 1 SD-IV San Diego, Esco Battery SDG&E ESCNDO_6_EB2BT2 22256 ESCNDIDO 69 10.00 1 SD-IV San Diego, Esco Battery SDG&E ESCNDO_6_EB3BT3 22256 ESCNDIDO 69 10.00 1 SD-IV San Diego, Esco Battery

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SDG&E ESCNDO_6_PL1X2 22257 ESGEN 13.8 48.71 1 SD-IV San Diego, Esco Market SDG&E ESCNDO_6_UNITB1 22153 CALPK_ES 13.8 48.00 1 SD-IV San Diego, Esco Market SDG&E ESCO_6_GLMQF 22332 GOALLINE 69 36.41 1 SD-IV San Diego, Esco Aug NQC Net Seller SDG&E IVSLRP_2_SOLAR1 23440 DW GEN2 G1 0.36 82.00 1 SD-IV None Aug NQC Market SDG&E IVWEST_2_SOLAR1 23155 DU GEN1 G1 0.2 33.27 G1 SD-IV None Aug NQC Market SDG&E IVWEST_2_SOLAR1 23156 DU GEN1 G2 0.2 28.23 G2 SD-IV None Aug NQC Market SDG&E JACMSR_1_JACSR1 23352 ECO GEN2 0.55 8.20 1 SD-IV None Aug NQC Market SDG&E LAKHDG_6_UNIT 1 22625 LKHODG1 13.8 20.00 1 SD-IV San Diego Market SDG&E LAKHDG_6_UNIT 2 22626 LKHODG2 13.8 20.00 2 SD-IV San Diego Market SDG&E LARKSP_6_UNIT 1 22074 LRKSPBD1 13.8 46.00 1 SD-IV San Diego, Border Market SDG&E LARKSP_6_UNIT 2 22075 LRKSPBD2 13.8 46.00 1 SD-IV San Diego, Border Market Connect to CENACE/CF E grid for the SDG&E LAROA1_2_UNITA1 20187 LRP-U1 16 0.00 1 SD-IV None summer – Market not available for ISO BAA RA purpose SDG&E LAROA2_2_UNITA1 22996 INTBST 18 145.19 1 SD-IV None Market SDG&E LAROA2_2_UNITA1 22997 INTBCT 16 176.81 1 SD-IV None Market SDG&E LILIAC_6_SOLAR 22404 LILIAC 69 1.23 DG SD-IV San Diego Market San Diego, SDG&E MRGT_6_MEF2 22487 MEF_MR2 13.8 47.90 1 SD-IV Market Miramar San Diego, SDG&E MRGT_6_MMAREF 22486 MEF_MR1 13.8 48.00 1 SD-IV Market Miramar San Diego, SDG&E MSHGTS_6_MMARLF 22448 MESAHGTS 69 4.42 1 SD-IV Aug NQC Market Mission SDG&E MSSION_2_QF 22496 MISSION 69 0.65 1 SD-IV San Diego Aug NQC Market Not modeled SDG&E MURRAY_6_UNIT 22532 MURRAY 69 0.00 SD-IV San Diego Market Energy Only SDG&E NIMTG_6_NIQF 22576 NOISLMTR 69 36.15 1 SD-IV San Diego Aug NQC QF/Selfgen SDG&E OCTILO_5_WIND 23314 OCO GEN G1 0.69 35.12 G1 SD-IV None Aug NQC Wind SDG&E OCTILO_5_WIND 23318 OCO GEN G2 0.69 35.12 G2 SD-IV None Aug NQC Wind SDG&E OGROVE_6_PL1X2 22628 PA GEN1 13.8 48.00 1 SD-IV San Diego, Pala Market SDG&E OGROVE_6_PL1X2 22629 PA GEN2 13.8 48.00 1 SD-IV San Diego, Pala Market Not modeled SDG&E OTAY_6_LNDFL5 22604 OTAY 69 0.00 SD-IV San Diego, Border Market Energy Only

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Not modeled SDG&E OTAY_6_LNDFL6 22604 OTAY 69 0.00 SD-IV San Diego, Border Market Energy Only SDG&E OTAY_6_PL1X2 22617 OYGEN 13.8 35.50 1 SD-IV San Diego, Border Market SDG&E OTAY_6_UNITB1 22604 OTAY 69 2.16 1 SD-IV San Diego, Border Aug NQC Market SDG&E OTAY_7_UNITC1 22604 OTAY 69 1.78 3 SD-IV San Diego, Border Aug NQC QF/Selfgen SDG&E OTMESA_2_PL1X3 22605 OTAYMGT1 18 165.16 1 SD-IV San Diego Market SDG&E OTMESA_2_PL1X3 22606 OTAYMGT2 18 166.17 1 SD-IV San Diego Market SDG&E OTMESA_2_PL1X3 22607 OTAYMST1 16 272.27 1 SD-IV San Diego Market SDG&E PALOMR_2_PL1X3 22262 PEN_CT1 18 170.18 1 SD-IV San Diego Market SDG&E PALOMR_2_PL1X3 22263 PEN_CT2 18 170.18 1 SD-IV San Diego Market SDG&E PALOMR_2_PL1X3 22265 PEN_ST 18 225.24 1 SD-IV San Diego Market No NQC - SDG&E PIOPIC_2_CTG1 23162 PIO PICO CT1 13.8 106.00 1 SD-IV San Diego Market Pmax No NQC - SDG&E PIOPIC_2_CTG2 23163 PIO PICO CT2 13.8 106.00 1 SD-IV San Diego Market Pmax No NQC - SDG&E PIOPIC_2_CTG3 23164 PIO PICO CT3 13.8 106.00 1 SD-IV San Diego Market Pmax SDG&E PTLOMA_6_NTCCGN 22660 POINTLMA 69 2.12 2 SD-IV San Diego Aug NQC QF/Selfgen SDG&E PTLOMA_6_NTCQF 22660 POINTLMA 69 19.76 1 SD-IV San Diego Aug NQC QF/Selfgen SDG&E SAMPSN_6_KELCO1 22704 SAMPSON 12.5 3.27 1 SD-IV San Diego Aug NQC Net Seller SDG&E SMRCOS_6_LNDFIL 22724 SANMRCOS 69 1.50 1 SD-IV San Diego Aug NQC Market SDG&E TERMEX_2_PL1X3 22982 TDM CTG2 18 156.44 1 SD-IV None Market SDG&E TERMEX_2_PL1X3 22983 TDM CTG3 18 156.44 1 SD-IV None Market SDG&E TERMEX_2_PL1X3 22981 TDM STG 21 280.13 1 SD-IV None Market SDG&E VLCNTR_6_VCSLR 22870 VALCNTR 69 0.96 DG SD-IV San Diego, Pala Aug NQC Market SDG&E VLCNTR_6_VCSLR1 22870 VALCNTR 69 1.03 DG SD-IV San Diego, Pala Aug NQC Market SDG&E VLCNTR_6_VCSLR2 22870 VALCNTR 69 2.05 DG SD-IV San Diego, Pala Aug NQC Market No NQC - SDG&E ZZ_NA 22916 PFC-AVC 0.6 0.00 1 SD-IV San Diego QF/Selfgen hist. data No NQC - SDG&E ZZZ_New Unit 23541 Q1061_BESS 0.48 20.00 1 SD-IV San Diego, Esco Battery est. data No NQC - SDG&E ZZZ_New Unit 23287 Q429_G1 0.31 41.00 1 SD-IV None Market est. data SDG&E ZZZ_New Unit 23441 DW GEN2 G2 0.42 61.60 1 SD-IV None Aug NQC Market EA5 No NQC - SDG&E ZZZ_New unit 22783 13.8 100.00 1 SD-IV San Diego Market REPOWER1 Pmax

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EA5 No NQC - SDG&E ZZZ_New unit 22784 13.8 100.00 1 SD-IV San Diego Market REPOWER2 Pmax EA5 No NQC - SDG&E ZZZ_New unit 22788 13.8 100.00 1 SD-IV San Diego Market REPOWER3 Pmax EA5 No NQC - SDG&E ZZZ_New unit 22786 13.8 100.00 1 SD-IV San Diego Market REPOWER4 Pmax EA5 No NQC - SDG&E ZZZ_New unit 22787 13.8 100.00 1 SD-IV San Diego Market REPOWER5 Pmax No NQC - SDG&E ZZZ_New Unit 23216 Q1294_BESS 0.48 20.00 C9 SD-IV San Diego, Esco Battery est. data BUE GEN No NQC - SDG&E ZZZ_New Unit 22942 0.69 11.60 G1 SD-IV None Wind 1_G1 est. data BUE GEN No NQC - SDG&E ZZZ_New Unit 22945 0.69 11.60 G2 SD-IV None Wind 1_G2 est. data BUE GEN No NQC - SDG&E ZZZ_New Unit 22947 0.69 11.60 G3 SD-IV None Wind 1_G3 est. data DW GEN2 SDG&E ZZZZ_New Unit 23443 0.6 43.09 1 SD-IV None Aug NQC Market G3B DW GEN2 SDG&E ZZZZ_New Unit 23442 0.6 60.35 1 SD-IV None Aug NQC Market G3A SDG&E ZZZZ_New Unit 23131 Q183_G1 0.69 0.00 G1 SD-IV None Energy Only Market SDG&E ZZZZ_New Unit 23134 Q183_G2 0.69 0.00 G2 SD-IV None Energy Only Market BUE GEN No NQC - SDG&E ZZZZ_New Unit 22949 0.69 26.00 G3 SD-IV None Wind 1_G4 est. data San Diego, El SDG&E ZZZZZ_ELCAJN_7_GT1 22212 ELCAJNGT 12.5 0.00 1 SD-IV Retired Market Cajon SDG&E ZZZZZ_ENCINA_7_EA1 22233 ENCINA 1 14.4 0.00 1 SD-IV San Diego, Encina Retired Market Retired by SDG&E ZZZZZ_ENCINA_7_EA2 22234 ENCINA 2 14.4 0.00 1 SD-IV San Diego, Encina Market 2019 Retired by SDG&E ZZZZZ_ENCINA_7_EA3 22236 ENCINA 3 14.4 0.00 1 SD-IV San Diego, Encina Market 2019 Retired by SDG&E ZZZZZ_ENCINA_7_EA4 22240 ENCINA 4 22 0.00 1 SD-IV San Diego, Encina Market 2019 Retired by SDG&E ZZZZZ_ENCINA_7_EA5 22244 ENCINA 5 24 0.00 1 SD-IV San Diego, Encina Market 2019 Retired by SDG&E ZZZZZ_ENCINA_7_GT1 22248 ENCINAGT 12.5 0.00 1 SD-IV San Diego, Encina Market 2019 San Diego, SDG&E ZZZZZ_KEARNY_7_KY2 22373 KEARN2AB 12.5 0.00 1 SD-IV Retired Market Mission

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San Diego, SDG&E ZZZZZ_KEARNY_7_KY2 22374 KEARN2CD 12.5 0.00 1 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_KEARNY_7_KY2 22373 KEARN2AB 12.5 0.00 2 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_KEARNY_7_KY2 22374 KEARN2CD 12.5 0.00 2 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_KEARNY_7_KY3 22375 KEARN3AB 12.5 0.00 1 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_KEARNY_7_KY3 22376 KEARN3CD 12.5 0.00 1 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_KEARNY_7_KY3 22375 KEARN3AB 12.5 0.00 2 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_KEARNY_7_KY3 22376 KEARN3CD 12.5 0.00 2 SD-IV Retired Market Mission San Diego, SDG&E ZZZZZ_MRGT_7_UNITS 22488 MIRAMRGT 12.5 0.00 1 SD-IV Retired Market Miramar San Diego, SDG&E ZZZZZ_MRGT_7_UNITS 22488 MIRAMRGT 12.5 0.00 2 SD-IV Retired Market Miramar

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VI. Appendix B – Effectiveness factors for procurement guidance

Table - Eagle Rock. Effectiveness factors to the Eagle Rock-Cortina 115 kV line:

Gen Bus Gen Name Gen ID Eff Fctr (%) 31406 GEYSR5-6 1 36 31406 GEYSR5-6 2 36 31408 GEYSER78 1 36 31408 GEYSER78 2 36 31412 GEYSER11 1 37 31435 GEO.ENGY 1 35 31435 GEO.ENGY 2 35 31433 POTTRVLY 1 34 31433 POTTRVLY 3 34 31433 POTTRVLY 4 34 38020 CITY UKH 1 32 38020 CITY UKH 2 32

Table - Fulton Effectiveness factors to the Lakeville-Petaluma-Cotati 60 kV line:

Gen Bus Gen Name Gen ID Eff Fctr (%) 31466 SONMA LF 1 52 31422 GEYSER17 1 12 31404 WEST FOR 1 12 31404 WEST FOR 2 12 31414 GEYSER12 1 12 31418 GEYSER14 1 12 31420 GEYSER16 1 12 31402 BEAR CAN 1 12 31402 BEAR CAN 2 12 38110 NCPA2GY1 1 12 38112 NCPA2GY2 1 12 32700 MONTICLO 1 10 32700 MONTICLO 2 10 32700 MONTICLO 3 10 31435 GEO.ENGY 1 6 31435 GEO.ENGY 2 6 31408 GEYSER78 1 6 31408 GEYSER78 2 6 31412 GEYSER11 1 6 31406 GEYSR5-6 1 6 31406 GEYSR5-6 2 6

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Table - Lakeville Effectiveness factors to the Vaca Dixon-Lakeville 230 kV line:

Gen Bus Gen Name Gen ID Eff Fctr (%) 31400 SANTA FE 2 38 31430 SMUDGEO1 1 38 31400 SANTA FE 1 38 31416 GEYSER13 1 38 31424 GEYSER18 1 38 31426 GEYSER20 1 38 38106 NCPA1GY1 1 38 38108 NCPA1GY2 1 38 31421 BOTTLERK 1 36 31404 WEST FOR 2 36 31402 BEAR CAN 1 36 31402 BEAR CAN 2 36 31404 WEST FOR 1 36 31414 GEYSER12 1 36 31418 GEYSER14 1 36 31420 GEYSER16 1 36 31422 GEYSER17 1 36 38110 NCPA2GY1 1 36 38112 NCPA2GY2 1 36 31446 SONMA LF 1 36 32700 MONTICLO 1 31 32700 MONTICLO 2 31 32700 MONTICLO 3 31 31406 GEYSR5-6 1 18 31406 GEYSR5-6 2 18 31405 RPSP1014 1 18 31408 GEYSER78 1 18 31408 GEYSER78 2 18 31412 GEYSER11 1 18 31435 GEO.ENGY 1 18 31435 GEO.ENGY 2 18 31433 POTTRVLY 1 15 31433 POTTRVLY 2 15 31433 POTTRVLY 3 15 38020 CITY UKH 1 15 38020 CITY UKH 2 15

Table – Rio Oso Effectiveness factors to the Rio Oso-Atlantic 230 kV line:

Gen Bus Gen Name Gen ID Eff Fctr. (%) 32498 SPILINCF 1 49

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32500 ULTR RCK 1 49 32456 MIDLFORK 1 33 32456 MIDLFORK 2 33 32458 RALSTON 1 33 32513 ELDRADO1 1 32 32514 ELDRADO2 1 32 32510 CHILIBAR 1 32 32486 HELLHOLE 1 31 32508 FRNCH MD 1 30 32460 NEWCSTLE 1 26 32478 HALSEY F 1 24 32512 WISE 1 24 38114 Stig CC 1 14 38123 Q267CT 1 14 38124 Q267ST 1 14 32462 CHI.PARK 1 8 32464 DTCHFLT1 1 4

Table – South of Table Mountain Effectiveness factors to the Caribou-Palermo 115 kV line:

Gen Bus Gen Name Gen ID Eff Fctr. (%) 31814 FORBSTWN 1 7 31794 WOODLEAF 1 7 31832 SLY.CR. 1 7 31862 DEADWOOD 1 7 31890 PO POWER 1 6 31890 PO POWER 2 6 31888 OROVLLE 1 6 31834 KELLYRDG 1 6 32450 COLGATE1 1 4 32466 NARROWS1 1 4 32468 NARROWS2 1 4 32452 COLGATE2 1 4 32470 CMP.FARW 1 4 32451 FREC 1 4 32490 GRNLEAF1 1 4 32490 GRNLEAF1 2 4 32496 YCEC 1 4 32494 YUBA CTY 1 4 32492 GRNLEAF2 1 4 32498 SPILINCF 1 2 31788 ROCK CK2 1 2 31812 CRESTA 1 2 31812 CRESTA 2 2 31820 BCKS CRK 1 2 31820 BCKS CRK 2 2

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31786 ROCK CK1 1 2 31790 POE 1 1 2 31792 POE 2 1 2 31784 BELDEN 1 2 32500 ULTR RCK 1 2 32156 WOODLAND 1 2 32510 CHILIBAR 1 2 32513 ELDRADO1 1 2 32514 ELDRADO2 1 2 32478 HALSEY F 1 2 32460 NEWCSTLE 1 1 32458 RALSTON 1 1 32512 WISE 1 1 32456 MIDLFORK 1 1 32456 MIDLFORK 2 1 32486 HELLHOLE 1 1 32508 FRNCH MD 1 1 32162 RIV.DLTA 1 1 32502 DTCHFLT2 1 1 32462 CHI.PARK 1 1 32464 DTCHFLT1 1 1 32454 DRUM 5 1 1 32476 ROLLINSF 1 1 32484 OXBOW F 1 1 32474 DEER CRK 1 1 32504 DRUM 1-2 1 1 32504 DRUM 1-2 2 1 32506 DRUM 3-4 1 1 32506 DRUM 3-4 2 1 32166 UC DAVIS 1 1 32472 SPAULDG 1 1 32472 SPAULDG 2 1 32472 SPAULDG 3 1 32480 BOWMAN 1 1 32488 HAYPRES+ 1 1 32488 HAYPRES+ 2 1 38124 LODI ST1 1 1 38123 LODI CT1 1 1 38114 STIG CC 1 1

Table – San Jose Effectiveness factors to the Newark-NRS 115 kV line. Bus# Bus Name ID Eff Factor % 36895 Gia200 1 25 36858 Gia100 1 25

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36859 Laf300 2 23 36859 Laf300 1 23 36863 DVRaGT1 1 23 36864 DVRbGt2 1 23 36865 DVRaST3 1 23 35854 LECEFGT1 1 19 35855 LECEFGT2 1 19 35856 LECEFGT3 1 19 35857 LECEFGT4 1 19 35858 LECEFST1 1 19 35860 OLS-AGNE 1 19 35863 CATALYST 1 12

Table – South Bay-Moss Landing Effectiveness factors to the Moss Landing-Las Aguillas 230 kV line. Bus# Bus Name ID Eff Factor % 36209 SLD ENRG 1 20 36221 DUKMOSS1 1 20 36222 DUKMOSS2 1 20 36223 DUKMOSS3 1 20 36224 DUKMOSS4 1 20 36225 DUKMOSS5 1 20 36226 DUKMOSS6 1 20 36405 MOSSLND6 1 17 36406 MOSSLND7 1 17 35881 MEC CTG1 1 13 35882 MEC CTG2 1 13 35883 MEC STG1 1 13 35850 GLRY COG 1 12 35850 GLRY COG 2 12 35851 GROYPKR1 1 12 35852 GROYPKR2 1 12 35853 GROYPKR3 1 12 35623 SWIFT BT 10 35863 CATALYST 1 10 36863 DVRaGT1 1 8 36864 DVRbGt2 1 8 36865 DVRaST3 1 8 36859 Laf300 2 8 36859 Laf300 1 8 36858 Gia100 1 7 36895 Gia200 1 7 35854 LECEFGT1 1 7 35855 LECEFGT2 1 7 35856 LECEFGT3 1 7 35857 LECEFGT4 1 7

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35858 LECEFST1 1 7 35860 OLS-AGNE 1 7

Table – Ames/Pittsburg/Oakland 1) Effectiveness factors to the Ames-Ravenswood #1 115 kV line. Bus# Bus Name ID Eff Factor % 35304 RUSELCT1 1 10 35305 RUSELCT2 2 10 35306 RUSELST1 3 10 33469 OX_MTN 1 10 33469 OX_MTN 2 10 33469 OX_MTN 3 10 33469 OX_MTN 4 10 33469 OX_MTN 5 10 33469 OX_MTN 6 10 33469 OX_MTN 7 10 33107 DEC STG1 1 3 33108 DEC CTG1 1 3 33109 DEC CTG2 1 3 33110 DEC CTG3 1 3 33102 COLUMBIA 1 3 33111 LMECCT2 1 3 33112 LMECCT1 1 3 33113 LMECST1 1 3 33151 FOSTER W 1 2 33151 FOSTER W 2 2 33151 FOSTER W 3 2 33136 CCCSD 1 2 33141 SHELL 1 1 2 33142 SHELL 2 1 2 33143 SHELL 3 1 2 32900 CRCKTCOG 1 2 32910 UNOCAL 1 2 32910 UNOCAL 2 2 32910 UNOCAL 3 2 32920 UNION CH 1 2 32921 ChevGen1 1 2 32922 ChevGen2 1 2 32923 ChevGen3 3 2 32741 HILLSIDE_12 1 2 32901 OAKLND 1 1 1 32902 OAKLND 2 2 1 32903 OAKLND 3 3 1 38118 ALMDACT1 1 1 38119 ALMDACT2 1 1

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2) Effectiveness factors to the Moraga-Claremont #2 115 kV line. Bus# Bus Name ID Eff Factor % 32741 HILLSIDE_12 1 15 32921 ChevGen1 1 15 32922 ChevGen2 1 15 32923 ChevGen3 3 15 32920 UNION CH 1 14 32910 UNOCAL 1 13 32910 UNOCAL 2 13 32910 UNOCAL 3 13 32901 OAKLND 1 1 10 32902 OAKLND 2 2 10 32903 OAKLND 3 3 10 38118 ALMDACT1 1 10 38119 ALMDACT2 1 10 33141 SHELL 1 1 9 33142 SHELL 2 1 9 33143 SHELL 3 1 9 33136 CCCSD 1 8 32900 CRCKTCOG 1 7 33151 FOSTER W 1 6 33151 FOSTER W 2 6 33151 FOSTER W 3 6 33102 COLUMBIA 1 3 33111 LMECCT2 1 3 33112 LMECCT1 1 3 33113 LMECST1 1 3 33107 DEC STG1 1 3 33108 DEC CTG1 1 3 33109 DEC CTG2 1 3 33110 DEC CTG3 1 3

Table – Herndon Effectiveness factors to the Herndon-Manchester 115 kV line.

Bus# Bus Name ID Eff Factor% 34624 BALCH 1 1 21.838 34616 KINGSRIV 1 20.665 34648 DINUBA E 1 19.515 34671 KRCDPCT1 1 19.43 34672 KRCDPCT2 1 19.43 34308 KERCKHOF 1 17.441 34343 KERCK1-2 2 17.441 34344 KERCK1-1 1 17.441 34345 KERCK1-3 3 17.441

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34603 JGBSWLT ST 14.719 34677 Q558 1 14.719 34690 CORCORAN_3 FW 14.719 34692 CORCORAN_4 FW 14.719 CORCORANPV_ 34696 S 1 14.719 34699 Q529 1 14.719 34610 HAAS 1 13.43 34610 HAAS 2 13.43 34612 BLCH 2-2 1 13.43 34614 BLCH 2-3 1 13.43 34431 GWF_HEP1 1 8.487 34433 GWF_HEP2 1 8.487 34617 Q581 1 4.723 34649 Q965 1 4.723 34680 KANSAS 1 4.723 34467 GIFFEN_DIST 1 3.701 34563 STROUD_DIST 2 3.701 34563 STROUD_DIST 1 3.701 34608 AGRICO 2 3.701 34608 AGRICO 3 3.701 34608 AGRICO 4 3.701 34644 Q679 1 3.701

36550 Q632BC1 1 3.701

Table – LA Basin Effectiveness factors to the Mesa – Laguna Bell #1 230 kV line: Resource Locations Effectiveness Factor (%)

REFUSE 13.8 #D1 -34.52 MALBRG1G 13.8 #C1 -34.42 ELSEG6ST 13.8 #6 -26.66 ELSEG5GT 16.5 #5 -26.64 VENICE 13.8 #1 -26.22 MOBGEN1 13.8 #1 -26.18 PALOGEN 13.8 #D1 -26.18 ARCO 1G 13.8 #1 -23.13 HARBOR G 13.8 #1 -23.03 THUMSGEN 13.8 #1 -23.03 CARBGEN1 13.8 #1 -23.02 SERRFGEN 13.8 #D1 -23.02 ICEGEN 13.8 #D1 -22.33 ALMITOSW 66.0 #l3 -18.01 ALAMTX1 18.0 #X1 -17.93

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CTRPKGEN 13.8 #1 -17.51 SIGGEN 13.8 #D1 -17.51 BARRE 66.0 #m3 -12.76 BARPKGEN 13.8 #1 -12.71 RIOHONDO 66.0 #l8 -12.50 WALNUT 66.0 #l3 -12.29 OLINDA 66.0 #1 -12.07 EME WCG1 13.8 #1 -12.00 BREAPWR2 13.8 #C4 -11.98 ELLIS 66.0 #l7 -11.98 JOHANNA 66.0 #l5 -11.42 SANTIAGO 66.0 #l8 -10.63 DowlingCTG 13.8 #1 -9.62 CanyonGT 1 13.8 #1 -9.58

VILLA PK 66.0 #l2 -9.29

Table – Rector Effectiveness factors to the Rector-Vestal 230 kV line:

Gen Bus Gen Name Gen ID MW Eff Fctr (%) 24370 KAWGEN 1 51 24306 B CRK1-1 1 45 24306 B CRK1-1 2 45 24307 B CRK1-2 3 45 24307 B CRK1-2 4 45 24319 EASTWOOD 1 45 24323 PORTAL 1 45 24308 B CRK2-1 1 45 24308 B CRK2-1 2 45 24309 B CRK2-2 3 45 24309 B CRK2-2 4 45 24310 B CRK2-3 5 45 24310 B CRK2-3 6 45 24315 B CRK 8 81 45 24315 B CRK 8 82 45 24311 B CRK3-1 1 45 24311 B CRK3-1 2 45 24312 B CRK3-2 3 45 24312 B CRK3-2 4 45 24313 B CRK3-3 5 45 24317 MAMOTH1G 1 45 24318 MAMOTH2G 2 45 24314 B CRK 4 41 43

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24314 B CRK 4 42 43

Table – San Diego Effectiveness factors to the Imperial Valley – El Centro 230 kV line (i.e., the “S” line): GENERATOR MW Eff Factor (%) INTBCT 16.0 #1 25.42 INTBST 18.0 #1 25.42 DW GEN2 G1 0.4 #1 25.18 DW GEN1 G1 0.3 #G1 25.15 DU GEN1 G2 0.2 #G2 25.14 DW GEN1 G2 0.3 #G2 25.14 DU GEN1 G1 0.2 #G1 25.08 DW GEN3&4 0.3 #1 25.08 OCO GEN G1 0.7 #G1 22.71 OCO GEN G2 0.7 #G2 22.71 ECO GEN1 G 0.7 #G1 21.85 Q644G 0.3 #1 21.11 OTAYMGT1 18.0 #1 17.82 OTAYMGT2 18.0 #1 17.82 OTAYMST1 16.0 #1 17.82 PIO PICO 1 13.8 #1 17.52 PIO PICO 1 13.8 #1 17.52 PIO PICO 1 13.8 #1 17.52 KUMEYAAY 0.7 #1 17.05 EC GEN2 13.8 #1 16.91 EC GEN1 13.8 #1 16.89 OY GEN 13.8 #1 16.82 OTAY 69.0 #1 16.81 OTAY 69.0 #3 16.81 DIVISION 69.0 #1 16.78 NOISLMTR 69.0 #1 16.75 SAMPSON 12.5 #1 16.69 CABRILLO 69.0 #1 16.62 LRKSPBD1 13.8 #1 16.56 LRKSPBD2 13.8 #1 16.56 POINTLMA 69.0 #2 16.56 CALPK_BD 13.8 #1 16.55

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MESAHGTS 69.0 #1 16.48 CARLTNHS 138.0 #1 16.46 CARLTNHS 138.0 #2 16.46 MISSION 69.0 #1 16.39 EASTGATE 69.0 #1 16.25 MEF MR1 13.8 #1 16.23 CHCARITA 138.0 #1 16.21 MEF MR2 13.8 #1 16.08 LkHodG1 13.8 #1 15.60 LkHodG2 13.8 #1 15.60 GOALLINE 69.0 #1 15.23 PEN_CT1 18.0 #1 14.98 CALPK_ES 13.8 #1 14.97 ENCINA 2 14.4 #1 14.96 ES GEN 13.8 #1 14.96 PEN_CT2 18.0 #1 14.93 PEN_ST 18.0 #1 14.92 SANMRCOS 69.0 #1 14.84 PA GEN1 13.8 #1 14.40 PA GEN2 13.8 #1 14.40 BR GEN1 0.2 #1 13.67 CAPSTRNO 138.0 #1 11.88 Resources connected to Imperial Valley substation or nearby SDG&E-owned substations in the area are most effective in mitigating the S-Line overload concern.

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APPENDIX A: System Data

California ISO/MID A-1

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Intentionally left blank

California ISO/MID A-2

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1 Existing Generation

Table A1-1: Existing generation plants in PG&E planning area

Planning Area Generating Plant Maximum Capacity

Humboldt Bay 166

Kekawaka 4.9

LP Samoa 25 PG&E -

Humboldt Fairhaven 17.3

Blue Lake 12

Humboldt Area Total 225

Santa Fe 160

Bear Canyon 20

Westford Flat 30

Western Geo 38

Geysers 5 53

Geysers 6 53

Geysers 7 53

Geysers 8 53 PG&E - North Coast and Geysers 11 106 North Bay Geysers 12 106

Geysers 13 133

Geysers 14 109

Geysers 16 118

Geysers 17 118

Geysers 18 118

Geysers 20 118

SMUD Geo 72

California ISO/MID A-3

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Planning Area Generating Plant Maximum Capacity

Potter Valley 11

Geo Energy 20

Indian Valley 3

Sonoma Landfill 6

Exxon 54

Monticello 12

North Coast and North Bay Area Total 1564

Pit River 752

Battle Creek 17

Cow Creek 5

North Feather River 736

South Feather River 123 PG&E - West Feather River 26 North Valley Black Butte 11

CPV 717

Hatchet Ridge Wind 103

QFs 353

North Valley Area Total 2,843

Wadham 27

Woodland Biomass 25

UC Davis Co-Gen 4 PG&E - Cal-Peak Vaca Dixon 49 Central Valley Wolfskill Energy Center 60

Lambie, Creed and Goosehaven 143

EnXco 60

California ISO/MID A-4

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Planning Area Generating Plant Maximum Capacity

Solano 100

High Winds 200

Shiloh 300

Bowman Power House 4

Camp Far West (SMUD) 7

Chicago Park Power House 40

Chili Bar Power House 7

Colgate Power House 294

Deer Creek Power House 6

Drum Power House 104

Dutch Plat Power House 49

El Dorado Power House 20

Feather River Energy Center 50

French Meadow Power House 17

Green Leaf No. 1 73

Green Leaf No. 2 50

Halsey Power House 11

Haypress Power House 15

Hellhole Power House 1

Middle Fork Power House 130

Narrows Power House 66

Newcastle Power House 14

Oxbow Power House 6

Ralston Power House 83

Rollins Power House 12

California ISO/MID A-5

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Planning Area Generating Plant Maximum Capacity

Spaulding Power House 17

SPI-Lincoln 18

Ultra Rock (Rio Bravo-Rocklin) 25

Wise Power House 20

Yuba City Co-Generation 49

Yuba City Energy Center 61

Altamont Co-Generation 7

Camanche Power House 11

Co-generation National POSDEF 44

Electra Power House 101

Flowind Wind Farms 76

GWF Tracy Peaking Plant 192

Ione Energy 18

Lodi CT 25

Lodi Stigg 57

Pardee Power House 29

Salt Springs Power House 42

San Joaquin Co-Generation 55

Simpson Paper Co-Generation 50

Stockton Co-Generation (Air Products) 50

Stockton Waste Water Facility 2

Thermal Energy 21

Tiger Creek Power House 55

US Wind Power Farms 158

West Point Power House 14

California ISO/MID A-6

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Planning Area Generating Plant Maximum Capacity

Lodi Energy Center 280

GWF Tracy Expansion 145

Beardsley Power House 11

Donnells Power House 68

Fiberboard (Sierra Pacific) 6

Melones Power Plant 119

Pacific Ultra Power Chinese Station 22

Sand Bar Power House 15

Spring Gap Power House 7

Stanislaus Power House 83

Stanislaus Waste Co-gen 24

Tullock Power House 17

Central Valley Area Total 3,970

Alameda Gas Turbines 51

Calpine Gilroy I 182

Crockett Co-Generation 240

Delta Energy Center 965

Marsh Landing 774

Russell City – East Shore EC 640 PG&E -

Greater Bay Area High Winds, LLC 162

Los Esteros Critical Energy Facility 362

Los Medanos Energy Center 678

Mariposa Peaker 200

Metcalf Energy Center 575

Oakland C Gas Turbines 165

California ISO/MID A-7

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Planning Area Generating Plant Maximum Capacity

Donald Von Raesfeld Power Plant 164

Shiloh Wind 500

Riverview Energy Center 61

Ox Mountain 13

Gateway Generating Station 599

Greater Bay Area Total 6331

Fresno Cogen-Agrico 79.9

Adams_E 19

Adera Solar 20

Alpaughn_20S 20

Alpaughn_50S 50

Atwell 20

Avenal 6

Balch 1 PH 31

Balch 2 PH 107 PG&E - Bulld 12 2.8 Greater Fresno Area Blackwell Solar 3

Mendota Biomass Power 25

Cantua 20

Chow 2 Peaker Plant 52.5

Chevron USA (Coalinga) 25

Chow II Biomass to Energy 12.5

CID Solar 20

Citizen Solar B 5

Coalinga Cogeneration Company 46

California ISO/MID A-8

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Planning Area Generating Plant Maximum Capacity

CalPeak Power – Panoche LLC 49

Crane Valley 0.9

Corcoran PB 20

Corcoran City 11

Dinuba Generation Project 13.5

El Nido Biomass to Energy 12.5

EE Kettleman Land 20

Exchequer Hydro 94.5

Fresno Waste Water 9

Friant Dam 27.3

Fresno Solar West & South 3

GWF Henrietta Peaker Plant 109.6

Gates_Dist 30

Giffen_Dist 10

Guernsey_Dist 20

HEP Peaker Plant Aggregate 102

Hanford L.P. 23

Hass PH Unit 1 &2 Aggregate 146.2

Helms Pump-Gen 1,212

J.R. Wood 10.8

Jgbswlt 2.9

Kansas 40

Kent 20

Kerkhoff PH1 32.8

Kerkhoff PH2 142

California ISO/MID A-9

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Planning Area Generating Plant Maximum Capacity

Kingsburg Cogen 34.5

Kings River Hydro 51.5

Kings River Conservation District 112

Liberty V Lost Hills 20

Madera 28.7

McCall 2.5

McSwain Hydro 10

Merced Falls 4

Merced Solar 1.5

Mission Solar 1.5

Morelos Del Sol 15

North Star Solar 1 60

O’Neill Pump-Gen 11

Panoche Energy Center 410

Pine Flat Hydro 189.9

Quinto Solar PV 107.6

Sanger Cogen 67.5

Sandrag 19

San Joaquin 2 3.2

San Joaquin 3 4.2

Schindler 30

Starwood Panoche 121.8

Stroud 20

Stratford 20

Suncity 20

California ISO/MID A-10

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Planning Area Generating Plant Maximum Capacity

SUN Harvest Solar 1.5

Rio Bravo Fresno (AKA Ultrapower) 26.5

Vega Solar 20

Wellhead Power Gates, LLC 49

Wellhead Power Panoche, LLC 49

Westlands 38

Westlands Solar Farm 18

Wishon/San Joaquin #1-A Aggregate 20.4

2097 Helton 1.5

Greater Fresno Area Total 4,316

Badger Creek (PSE) 49

Chalk Cliff 48

Cymric Cogen (Chevron) 21

Cadet (Chev USA) 12

Dexzel 33

Discovery 44

Double C (PSE) 45 PG&E - Elk Hills 623 Kern Area Frito Lay 8

Hi Sierra Cogen 49

Kern 177

Kern Canyon Power House 11

Kernfront 49

Kern Ridge (South Belridge) 76

La Paloma Generation 926

California ISO/MID A-11

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Planning Area Generating Plant Maximum Capacity

Midsun 25

Mt. Poso 56

Navy 35R 65

Oildale Cogen 40

Bear Mountain Cogen (PSE) 69

Live Oak (PSE) 48

McKittrick (PSE) 45

Rio Bravo Hydro 11

Shell S.E. Kern River 27

Solar Tannenhill 18

Sunset 225

North Midway (Texaco) 24

Sunrise (Texaco) 338

Sunset (Texaco) 239

Midset (Texaco) 42

Lost Hills (Texaco) 9

University Cogen 36

New RPS Units 55

Kern Area Total 3,543

Moss Landing Power Plant 1,020

Soledad Energy 10

PG&E - Basic Energy Cogen (King City) 133 Central Coast and Los Padres King City Peaker 70

Sargent Canyon Cogen (Oilfields) 45

Salinas River Cogen (Oilfields) 45

California ISO/MID A-12

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Planning Area Generating Plant Maximum Capacity

Diablo Canyon Power Plant 2,400

Union Oil (Tosco) 6

Santa Maria 8

Vandenberg Air Force Base 15

Topaz 550

California Valley Solar 250

Central Coast and Los Padres Area Total 4,552

California ISO/MID A-13

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Table A1-2: Existing generation plants in SCE planning area

Planning Area Generating Plant Maximum Capacity

Big Creek 1-1 Gen 1 19.9

Big Creek 1-1 Gen 2 21.6

Big Creek 1-2 Gen 3 21.6

Big Creek 1-2 Gen 4 31.2

Big Creek 2-1 Gen 1 50.8

Big Creek 2-1 Gen 2 52.0

Big Creek 2-2 Gen 3 18.7

Big Creek 2-2 Gen 4 19.7

Big Creek 2-3 Gen 5 17.0

Big Creek 2-3 Gen 6 18.5

SCE - Big Creek 3-1 Gen 1 35.0 Tehachapi and Big Creek Corridor Big Creek 3-1 Gen 2 35.0

Big Creek 3-2 Gen 3 35.0

Big Creek 3-2 Gen 4 41.0

Big Creek 3-3 Gen 5 39.0

Big Creek 4 Gen 41 50.4

Big Creek 4 Gen 41 50.6

Big Creek 8 Gen 81 24.4

Big Creek 8 Gen 81 44.0

Eastwood 207.0

Mamoth 1G 93.5

Mamoth 2G 93.5

Portal 9.6

Warne 1 38.0

California ISO/MID A-14

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Planning Area Generating Plant Maximum Capacity

Warne 2 38.0

Pandol 1 56.0

Pandol 2 56.0

Ultragen 41.0

Omar 1G 90.8

Omar 2G 90.8

Omar 3G 90.8

Omar 4G 90.8

SYCCYN 1G 75.0

SYCCYN 2G 75.0

SYCCYN 3G 75.0

SYCCYN 4G 75.0

Pastoria Energy Facility 770.0

Manzana Wind Project 189.0

Pacific Wind Project 140.0

Coram Brodie Wind Project Expansion 51.0

Coram Brodie Wind Project Phase 2 51.0

Alta 2012 720.0

CPC Alta Wind 4-5 (fka CPC East) 420.0

CPC Alta Wind 1-3 (fka CPC West) 600.0

Windstar I Alternate 120.0

Eastwind 60.0

Westwind 21.0

Tehachap 114.4

WNDT167 120.0

California ISO/MID A-15

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Planning Area Generating Plant Maximum Capacity

North Sky River Wind 170.0

Sky River 76.9

Catalina Solar 150.0

KR 3-1 22.8

KR 3-2 21.5

LakeGen 18.0

Wellhead Power Delano 49.9

Kawgen 18.0

Avenue 310.0

Kingsbird 270.0

AV Solar 1 249.0

Arbwind 21.8

Canwind 65.0

Enwind 47.1

Encawind 112.9

Flowind 40.8

Dutchwind 14.0

Northwind 19.4

Oakwind 21.1

Southwind 13.4

Zondwind 26.0

Breeze 12.5

Midwind 18.0

Morwind 56.0

Kern River 24.0

California ISO/MID A-16

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Planning Area Generating Plant Maximum Capacity

Borel 10.0

Alta Vista Suntower Generating Station 66.0

Antelope Power Plant 20.0

Down 20.0

Twilight 20.0

Antelope Valley PV1 318.5

Antelope Valley PV2 285.0

Rising Tree 198.8

Western Antelope Blue Sky Ranch A 20.0

First Solar North Rosamond 100.8

AV Solar Ranch 2-A 20.4

AV Solar Ranch 2-B 20.4

RE Astoria 181.1

RE Camelot 45.0

RE Columbia 15.0

TA Acacia 20.0

SGS Antelope Valley 300.0

North Rosamond 156.2

Tehachapi and Big Creek Corridor Total 8,410.9

Desert Star Energy Star 506

Mountain Pass - Ivanpah Solar 392 SCE - Copper Mountain Solar I 58 East of Lugo Area Copper Mountain Solar II 155

East of Lugo Area Total 1,111

California ISO/MID A-17

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Planning Area Generating Plant Maximum Capacity

ALBAG1 140

BLM E7G 24

BLM E8G 24

BLM W9G 19.5

BORAX I 22

BSPHYD26 14.18

BSPHYD34 15.9

BLM E7G 24

CALGEN 92.2

CSA DIABLO 1 15

CSA DIABLO 2 10

High Desert Power Plant 854.9 SCE -

North of Lugo KERRMGEE 15

LUNDY 3

LUZ (8 & 9) 160

NAVYII4G 22.5

NAVYII5G 22.5

NAVYII6G 22.5

OCASOG2 140

OXBOW G1 49.8

POOLE 10.9

RUSH 11.5

SEGS 1G 14.2

SEGS 2G 43.8

California ISO/MID A-18

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Planning Area Generating Plant Maximum Capacity

SUNGEN 150

North of Lugo Area Total 1,897

Blythe Energy Center 520

Indigo Peaker 136

Cabazon Wind 42.6

Mountainview IV Wind 42

Wintec 5 Wind 3.7

Wintec 6 Wind 45

Pacificorp Wind 2.1

FPLE Green 1 Wind 8.7

FPLE Green 2 Wind 3.0

FPLE Green 3 Wind 6.8

Wintec 2 Wind 16.5

Wintec 3 Wind 11.6

Wintec 4 Wind 16.5 SCE - Seawest 1 Wind 44.4 Eastern Area Seawest 2 Wind 22.2

Seawest 3 Wind 22.4

Renwind Wind 9.0

Whitewater Wind 66

Altamesa 4 Wind 40

Painted Hills Wind 16.9

Altwind QF 1 32.9

Altwind QF 2 15.1

Buchwind QF 17

California ISO/MID A-19

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Planning Area Generating Plant Maximum Capacity

Capwind QF 20

Garnet QF Wind 101.4

Panaero Wind 30

Renwind QF 1 6.3

Renwind QF 2 6.6

Sanwind QF 1 3.0

Sanwind QF 2 28.0

Seawind QF 27

Terawind QF 22.5

Transwind QF 40.0

Venwind QF 1 25.5

Venwind QF 2 19.3

CPV Sentinel Peaker 850

Genesis Solar Energy Project 250

Desert Sunlight PV Project 550

McCoy Photovoltaic Project1 126.16

Windustries 9.8

Edom Hills Wind Farm 20

Karen Avenue Wind Farm 11.7

Eastern Area Total 3,287.66

Agua Mansa Generating Facility 43

SCE Metro Area Alamitos 2,010

Anaheim CT 41

1 This project is partially operational at 126.16 MW, with a total capacity of 250 MW

California ISO/MID A-20

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Planning Area Generating Plant Maximum Capacity

AP North Lake Solar 20

Barre Peaker 45

Berry Petroleum Placerita 37

BP West Coast Products 21

Broadway 3 65

Calabasas Gas-to-Energy Facility 7

Canyon Power Plant 195

Carson Cogeneration Company 47

Center Area Lumped Units 18

Center Peaker 45

Century 36

Chevron CIC 170.7

Chiquita Canyon Landfill Generating Facility 7

City Of Long Beach 28

Clearwater Power Plant 28

Corona Energy Partners, Ltd. 30

County Of Los Angeles (Pitchess Honor 19 Ranch)

Coyote Canyon 6

Devil Canyon 235

Drews 36

E. F. Oxnard, Incorporated 34

El Segundo Energy Center 570

Ellwood Generating Station 54

Etiwanda Hydro Recovery Plant 10

California ISO/MID A-21

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Planning Area Generating Plant Maximum Capacity

Foothill Hydro Recovery Plant 8

Glen Arm Power Plant 132

Grapeland Peaker 43

H. Gonzales Gas Turbine 12

Harbor Cogen Combined Cycle 100

Houweling Nurseries Oxnard CHP 13.2

Huntington Beach 1 & 2 452

Inland Empire Energy Center 670

L.A. County Sanitation District #2 (Puente 47 Hills B)

Long Beach 1 – 4 260

Malburg Generating Facility 134

Mira Loma Peaker 43

MM West Coast Covina, LLC 6

Mojave Siphon PH 18

Mountainview Power Plant 969

MWD Perris Hydroelectric Recovery Plant 8

O.L.S. Energy Company- Chino-Mens Inst. 25

Ormond Beach 1,516

Procter & Gamble Paper Prod. (Oxnard II) 46

Redondo 1,356

Ripon Cogeneration 27

Riverside Energy Resource Center (RERC) 194

San Dimas Hydro Recovery Plant 8

Springs Generation Plant 36

California ISO/MID A-22

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Planning Area Generating Plant Maximum Capacity

SPVP044 8

Sunshine Gas Producers, L.L.C. 20

Tequesquite Landfill Solar Project 7.5

Walnut Creek Energy Park 500

Watson Cogeneration 406

Weyerhaeuser Company (Formerly 13 Williamette Industries)

Multiple smaller facilities 85.5

Metro Area Total 11,021

California ISO/MID A-23

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Table A1-3: Existing generation plants in SDG&E planning area

Planning Area Generating Plant Maximum Capacity

Otay Mesa GT1 185.1

Otay Mesa GT2 185.1

Otay Mesa ST1 233.5

Larkspur Border 1 46.0

Larkspur Border 2 46.0

Cabrillo 3.1

Capistrano 5.3

Carlton Hills 1.6

Carlton Hills 0.3

Chicarita 3.7

Border/Calpeak 48.0 SDG&E El Cajon/Calpeak 45.4

Escondido/Calpeak 48.0

DIVSON_6_NSQF 41.7

East Gate 0.3

Encina 2 104.0

Encina 3 110.0

Encina 5 300.0

Encina 4 330.0

Encina GT 14.5

MMC-Electrovest (Escondido) 49.5

Palomar_CT1 162.4

California ISO/MID A-24

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Planning Area Generating Plant Maximum Capacity

Palomar_CT2 162.4

Palomar_ST 240.8

Goalline 38.4

Mesa Heights 3.6

Miramar 1 48.0

Miramar 2 47.9

Mission 0.7

North Island 36.4

Otay Landfill I 2.8

Otay Landfill II 2.6

Covanta Otay 3 3.5

MMC-Electrovest (Otay) 35.5

Orange Grove 1 50.0

Orange Grove 2 50.0

NTC Point Loma Steam turbine 2.0

NTC Point Loma 19.4

Sampson 1.0

San Marcos Landfill 0.7

El Cajon Energy Center 48.1

Lake Hodges Pumped Storage 1 20.0

Lake Hodges Pumped Storage 2 20.0

BREGGO SOLAR (NQC) 26.0

Kumeyaay 50.0

California ISO/MID A-25

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Planning Area Generating Plant Maximum Capacity

East County 155.0

Ocotillo Express 265.0

Miramar GT 1 17.0

Miramar GT 2 16.0

Naval Station 47.0

El Cajon GT 13.0

Ash 0.9

Rancho Santa Fe 1 0.4

Rancho Santa Fe 2 0.3

Murray 0.2

Kyocera 0.1

SDG&E Area Total 3,388

California ISO/MID A-26

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Table A1-4: Existing generation plants in VEA planning area

Planning Area Generating Plant Maximum Capacity

Community Solar (WDAT) 15 VEA VEA Area Total 15

California ISO/MID A-27

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2 Retired Generation (non-OTC)

Table A2-1: Generation plants projected to be retired in planning horizon

First Year PTO Capacity Project to be Area (MW) retired

SCE Etiwanda 3 & 4 640 2018

SCE Mandalay Units 1,2,3 560 2018

SCE Ellwood 54 2021

California ISO/MID A-28

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3 Planned Generation

Table A3-1: Planned Generation

First Year PTO Capacity Project to be Area (MW) Modeled

PG&E - - -

Huntington Beach Energy Project Unit 6 (CCGT) * 644 2020 SCE Alamitos Energy Center Unit 8 (CCGT) * 640 2020

Stanton Energy Center* 98 2020

SDG&E Carlsbad Peakers* 500 2019

Notes:

*These projects have received PPTA approvals from the CPUC as part of Long Term Procurement Plan (LTPP) process.

California ISO/MID A-29

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4 Reactive Resources

Table A4-1: Summary of key existing reactive modeled in ISO reliability assessments Substation Capacity (Mvar) Gates 225 Los Banos 225 Gregg 150 McCall 132 Mesa 100 Metcalf 350 Olinda 200 Table Mountain 454 Devers 156 & 605 (dynamic capability) Rector 200 Santiago 243 Sunrise San Luis Rey 63 Southbay / Bay Boulevard 100 Miraloma 158 Suncrest 126 Penasquitos 126

California ISO/MID A-30

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5 Special Protection Schemes

Table A5-1: Existing Special Protection Schemes in the PG&E area

PTO Area SPS Name Central Coast / Los Mesa and Santa Maria Padres Undervoltage SPS Central Coast / Los Divide Undervoltage SPS Padres Temblor-San Luis Central Coast / Los Obispo 115 kV Overload Padres Scheme Bulk COI RAS Bulk Colusa SPS Bulk Diablo Canyon SPS Gates 500/230 kV Bank Bulk #11 SPS Midway 500/230 kV Bulk Transformer Overload SPS Bulk Path 15 IRAS PG&E Path 26 RAS North to Bulk South Path 26 RAS South to Bulk North Table Mt 500/230 kV Bulk Bank #1 SPS Drum (Sierra Pacific) Central Valley Overload Scheme (Path 24) Stanislaus – Manteca Central Valley 115 kV Line Load Limit Scheme Vaca-Suisun 115 kV Central Valley Lines Thermal Overload Scheme West Sacramento 115 Central Valley kV Overload Scheme

California ISO/MID A-31

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PTO Area SPS Name West Sacramento Double Line Outage Central Valley Load Shedding SPS Scheme Greater Fresno Area Ashlan SPS Greater Fresno Area Atwater SPS Greater Fresno Area Gates Bank 11 SPS Greater Fresno Area Helms HTT RAS Greater Fresno Area Helms RAS Greater Fresno Area Henrietta RAS Greater Fresno Area Herndon-Bullard SPS Greater Fresno Area Kerckhoff 2 RAS Greater Fresno Area Reedley SPS Greater Bay Area Metcalf SPS Greater Bay Area SF RAS Greater Bay Area South of San Mateo SPS Metcalf-Monta Vista Greater Bay Area 230kV OL SPS San Mateo-Bay Greater Bay Area Meadows 115kV line OL Moraga-Oakland J Greater Bay Area 115kV line OL RAS Greater Bay Area Grant 115kV OL SPS Oakland 115 kV C-X Greater Bay Area Cable OL RAS Oakland 115kV D-L Greater Bay Area Cable OL RAS Sobrante-Standard Oil Greater Bay Area #1 & #2-115kV line Greater Bay Area Gilroy SPS Transbay Cable Run Greater Bay Area Back Scheme Humboldt – Trinity 115kV Humboldt Thermal Overload Scheme Caribou Generation 230 North Valley kV SPS Scheme #1

California ISO/MID A-32

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PTO Area SPS Name Caribou Generation 230 North Valley kV SPS Scheme #2 Cascade Thermal North Valley Overload Scheme Hatchet Ridge Thermal North Valley Overload Scheme Coleman Thermal North Valley Overload Scheme

California ISO/MID A-33

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Table A5-2: Existing Special Protection Schemes in SCE area

PTO Area SPS Name Antelope-Bailey Antelope-RAS Big Creek / San Joaquin Big Creek Corridor Valley RAS North of Lugo Bishop RAS High Desert Power North of Lugo Project RAS North of Lugo Kramer RAS Antelope-Bailey Midway-Vincent RAS Lancaster N-2 Line Loss Antelope-Bailey Tripping Scheme Palmdale N-2 Line Loss Antelope-Bailey Tripping Scheme Pastoria Energy Facility Antelope-Bailey Existing RAS Reliant Energy Cool North of Lugo Water Stability Tripping Scheme West-of-Devers Eastern Area SCE Remedial Action Scheme Eastern Area Blythe Energy RAS Eagle Mountain Thermal Eastern Area Overload Scheme El Nido N-2 Remedial Metro Area Action Scheme Mountain view Power Metro Area Project Remedial Action Scheme South of Lugo N-2 Metro Area Remedial Action Scheme Mira Loma Low Voltage Metro Area Load Shedding Santiago N-2 Remedial Metro Area Action Scheme Valley Direct Load Trip Metro Area Remedial Action Scheme El Segundo N-2 Metro Area Remedial Action Scheme

California ISO/MID A-34

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Table A5-3: Existing Special Protection Schemes in the SDG&E

PTO Area SPS Name SDG&E TL695A at Talega SPS SDG&E TL682/TL685 SPS SDG&E TL633 At Rancho Carmel SPS SDG&E TL687 at Borrego SPS SDG&E TL13816 SPS SDG&E TL13835 SPS SDG&E Border TL649 Overload SPS Crestwood TL626 at DE SDG&E SPS for Kumeyaay Wind Generation Crestwood TL629 at CN SDG&E SPS for Kumeyaay Wind Generation Crestwood TL629 at DE SDG&E SDG&E SPS for Kumeyaay Wind Generation 230kV TL 23040 Otay Mesa – Tijuana SPS (currently disabled and SDG&E will not be enabled until its need is reevaluated with CFE) 230kV Otay Mesa SDG&E Energy Center Generation SPS ML (Miguel) Bank 80/81 SDG&E Overload SPS CFE SPS to protect lines SDG&E from La Rosita to Tijuana TL 50001 IV Generator SDG&E SPS Path 44 South of SDG&E SONGS Safety Net

California ISO/MID A-35

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Curtailed and Non-Operational Generators in California August, 2011

This list is posted in accordance with California public Utilities Code Section 352.5. Section 352.5 which requires the ISO to make publicly available daily a list of all power plants located in the state that are not operational due to a Planned or Unplanned outage. The ISO does not at this time have information regarding the operational status of all plants located in the state. Accordingly this list includes only the units regarding which the ISO has information.

Please be advised that system conditions are dynamic and this information is subject to change without further notice. Decisions based upon information contained in the California ISO site are the sole responsibility of the visitor.

Starting 10-Jul-2001, the California ISO publishes a snapshot of unit status. The anticipated publishing time for this snapshot report is 08:30 Pacific Time. This report reflects the status of units at the time that the report is produced. This snapshot is based on the best information available to the ISO. System conditions are dynamic and can change rapidly. This report also takes into account outages on resources with obligations to participants outside of the ISO Control Area. These unit outages reflect only the participation of the units output contracted into the CAISO control area. Sun Mon Tue Wed Thu Fri Sat

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Curtailed and Non-Operational Generators in California September, 2011

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