Generator Interconnection and Deliverability Study Methodology Technical Paper

Generator Interconnection and Deliverability Study Methodology Technical Paper July 2, 2013

Generator Interconnection and Deliverability Study Methodology Table of Contents Introduction... 1 Section One: Background Information on the Basis for the Methodology and an Overview of the Methodology... 3 Background... 3 Overview of the Methodology... 7 Section Two: On-Peak Generation Deliverability Assessment Methodology...17 Background...17 Study Objectives...18 Baseline analysis...18 General Procedures and Assumptions...19 Specific Assumptions...22 Section Three: Examples of Application of Deliverability Assessment Methodology...24 1. Whirlwind Example...27 2. Borrego Area Example...34 3. ECO/BUE Area Deliverability Constraint and Mitigation Example...41 4. North of Lugo Deliverability Constraints and Mitigations Example...50 5. Northern California Deliverability Constraint and Mitigation Example...62 6. Central California Example...78 7. Desert Area Deliverability Constraints and Mitigations Example (TPP)...94 8. Desert Area Deliverability Constraints and Mitigations Example (GIP)... 120 9. South of Vincent Deliverability Constraints and Mitigation Examples... 147 10. Path 43 (North of SONGS) Deliverability Constraint and Mitigation Example... 177 i

Generator Interconnection and Deliverability Study Methodology List of Figures Figure I-1: Electric transmission network in California... 8 Figure I-2: Electric power plant locations in California... 8 Figure I-3: Depiction of resource shortage Scenario 1 in California... 9 Figure I-4: Depiction of resource shortage Scenario 2 in California... 10 Figure I-5: Depiction of a Study Group Based on the 5% Distribution Factor Threshold... 12 Figure I-6: Example Production Duration Curve Showing 70% Exceedance Level... 14 Figure I-7: Example Production Duration Curve Showing Combined 70% Exceedance Level... 15 Figure I-8: Example Production Curve Showing Production Levels Counted by the 70% Exceedance Level Calculation... 15 Figure 1.1: Illustration of Generator Grouping for Whirlwind Transformer Bank Flows... 29 Figure 1.2: Initial Dispatch Whirlwind Transformers... 31 Figure 1.3: Stressed Dispatch Whirlwind Transformers... 32 Figure 1.4: Traditional Power Flow Dispatch Whirlwind Transformers... 33 Figure 2.1: Illustration of Generator Grouping for Borrego Area... 36 Figure 2.2: Initial Dispatch Borrego Area... 38 Figure 2.3: Stressed Dispatch Borrego Area... 39 Figure 2.4: Traditional Power Flow Dispatch Borrego Area... 40 Figure 3.1: Illustration of Generator Grouping for ECO/BUE Area... 43 Figure 3.2: Initial Dispatch ECO/BUE Area... 46 Figure 3.3: Stressed Dispatch ECO/BUE Area... 47 Figure 3.4: Stressed Dispatch with Mitigation ECO/BUE Area... 48 Figure 3.5: Off-Peak Study ECO/BUE Area... 49 Figure 4.1: Illustration of Generator Grouping for Kramer Lugo 230 kv No.1 & 2 Overloads... 53 Figure 4.2: Initial Dispatch North of Lugo... 57 Figure 4.3: Stressed Dispatch North of Lugo... 58 Figure 4.4: Stressed Dispatch with Mitigation North of Lugo... 59 Figure 4.5: Traditional Power Flow Dispatch North of Lugo... 60 Figure 4.6: Traditional Power Flow Dispatch with Mitigation North of Lugo... 61 Figure 5.1: Illustration of Generator Grouping for Vaca Dixon WindUnit_POI Constraint... 64 Figure 5.2: Initial Dispatch (Pre-Contingency) Vaca Dixon to WindUnit_POI Constraint... 71 Figure 5.3: Initial Dispatch (Post-Contingency) Vaca Dixon to WindUnit_POI Constraint... 72 Figure 5.4: Stressed Dispatch (Post-Contingency) Vaca Dixon to WindUnit_POI Constraint... 73 Figure 5.5: Stressed Dispatch with SPS Mitigation (Post-Contingency) Vaca Dixon to WindUnit_POI Constraint... 74 Figure 5.6: Traditional Power Flow (Pre-Contingency) Vaca Dixon to WindUnit_POI Constraint... 75 Figure 5.7: Traditional Power Flow (Post-Contingency) Vaca Dixon to WindUnit_POI Constraint... 76 Figure 5.8: Traditional Power Flow with SPS Mitigation (Post-Contingency) Vaca Dixon to WindUnit_POI Constraint... 77 Figure 6.1: Illustration of Generation Grouping for Panoche-Dos Amigos Flow... 80 Figure 6.2: Initial Dispatch (Pre-Contingency) Panoche to Dos Amigos Flow... 88 Figure 6.3: Initial Dispatch (Post-Contingency) Panoche to Dos Amigos Flow... 89 Figure 6.4: Stressed Dispatch (Pre-Contingency) Panoche to Dos Amigos Flow... Error! Bookmark not defined. Figure 6.5: Stressed Dispatch (Post-Contingency) Panoche to Dos Amigos Flow... Error! Bookmark not defined. ii

Generator Interconnection and Deliverability Study Methodology Figure 6.6: Stressed Dispatch with Mitigations for other Deliverability Constraints (Post-Contingency) Panoche to Dos Amigos Flow... 91 Figure 6.7: Traditional Power Flow Dispatch (Pre-Contingency) Panoche to Dos Amigos Flow... Error! Bookmark not defined. Figure 6.8: Traditional Power Flow Dispatch (Post-Contingency) Panoche to Dos Amigos Flow... Error! Bookmark not defined. Figure 6.9: Traditional Power Flow Dispatch with Mitigations for Other Deliverability Constraints (Post- Contingency) Panoche to Dos Amigos Flow... 93 Figure 7.1: Illustration of Generator Grouping for Lugo Victorville Constraint... 97 Figure 7.2: Initial Dispatch (Pre-Contingency) Lugo to Victorville Constraint... 108 Figure 7.3: Initial Dispatch (Post-Contingency) Lugo to Victorville Constraint... 109 Figure 7.4: Post-Dispatch of 1500 MW Generation (Pre-Contingency) Lugo to Victorville Constraint. 110 Figure 7.5: Post-Dispatch of 1500 MW Generation (Post-Contingency) Lugo to Victorville Constraint 111 Figure 7.6: Post-Dispatch of Facility Loading Adder (Pre-Contingency) Lugo to Victorville Constraint. 112 Figure 7.7: Post-Dispatch of Facility Loading Adder (Post-Contingency) Lugo to Victorville Constraint... 113 Figure 7.8: Post-Dispatch of Facility Loading Adder with Mitigation (Pre-Contingency) Lugo to Victorville Constraint... 114 Figure 7.9: Post-Dispatch of Facility Loading Adder with Mitigation (Post-Contingency) Lugo to Victorville Constraint... 115 Figure 7.10: Traditional Power Flow Dispatch (Pre-Contingency) Lugo to Victorville Constraint... 116 Figure 7.11: Traditional Power Flow Dispatch (Post-Contingency) Lugo to Victorville Constraint... 117 Figure 7.12: Traditional Power Flow Dispatch with Mitigation (Pre-Contingency) Lugo to Victorville Constraint... 118 Figure 7.13: Traditional Power Flow Dispatch with Mitigation (Post-Contingency) Lugo to Victorville Constraint... 119 Figure 8.1: Illustration of Generator Grouping for Lugo Eldorado Constraint... 123 Figure 8.2: Initial Dispatch (Pre-Contingency) Lugo to Eldorado Constraint... 133 Figure 8.3: Initial Dispatch (Post-Contingency) Lugo to Eldorado Constraint... 134 Figure 8.4: Post-Dispatch of 1500 MW Generation (Pre-Contingency) Lugo to Eldorado Constraint... 135 Figure 8.5: Post-Dispatch of 1500 MW Generation (Post-Contingency) Lugo to Eldorado Constraint. 136 Figure 8.6: Post-Dispatch of Facility Loading Adder (Pre-Contingency) Lugo to Eldorado Constraint.. 137 Figure 8.7: Post-Dispatch of Facility Loading Adder (Post-Contingency) Lugo to Eldorado Constraint. 138 Figure 8.8: Post-Dispatch of Facility Loading Adder with Lugo Eldorado Upgrade (Pre-Contingency) Lugo to Eldorado Constraint... 139 Figure 8.9: Post-Dispatch of Facility Loading Adder with Lugo Eldorado Upgrade (Post-Contingency) Lugo to Eldorado Constraint... 140 Figure 8.10: Post-Dispatch of Facility Loading Adder with Lugo Eldorado Upgrade & Red Bluff Valley Line (Pre-Contingency) Lugo to Eldorado Constraint... 141 Figure 8.11: Post-Dispatch of Facility Loading Adder with Lugo Eldorado Upgrade & Red Bluff Valley Line (Post-Contingency) Lugo to Eldorado Constraint... 142 Figure 8.12: Traditional Power Flow Dispatch (Pre-Contingency) Lugo to Eldorado Constraint... 143 Figure 8.13: Traditional Power Flow Dispatch (Post-Contingency) Lugo to Eldorado Constraint... 144 Figure 8.14: Traditional Power Flow Dispatch with Lugo Eldorado Upgrade & Red Bluff Valley Line (Pre-Contingency) Lugo to Eldorado Constraint... 145 Figure 8.15: Traditional Power Flow Dispatch with Lugo Eldorado Upgrade & Red Bluff Valley Line (Post-Contingency) Lugo to Eldorado Constraint... 146 Figure 9.1: Illustration of Generator Grouping for Vincent 500/230kV Transformer Overload... 150 iii

Generator Interconnection and Deliverability Study Methodology Figure 9.2: Initial Dispatch (Pre-Contingency) South of Vincent Constraint... 167 Figure 9.3: Initial Dispatch (Post-Contingency) South of Vincent Constraint... 168 Figure 9.4: Stressed Dispatch (Pre-Contingency) South of Vincent Constraint... 169 Figure 9.5: Stressed Dispatch (Post-Contingency) South of Vincent Constraint... 170 Figure 9.6: Initial Dispatch after Removing Generators (Pre-Contingency) South of Vincent Constraint... 171 Figure 9.7: Initial Dispatch after Removing Generators (Post-Contingency) South of Vincent Constraint... 172 Figure 9.8: Stressed Dispatch after Removing Generators (Pre-Contingency) South of Vincent Constraint... 173 Figure 9.9: Stressed Dispatch after Removing Generators (Post-Contingency) South of Vincent Constraint... 174 Figure 9.10: Traditional Power Flow after Removing Generators (Pre-Contingency) South of Vincent Constraint... 175 Figure 9.11: Traditional Power Flow after Removing Generators (Post-Contingency) South of Vincent Constraint... 176 Figure 10.1: Illustration of Generator Grouping for Path 43 Constraint... 182 Figure 10.2: Initial Dispatch Path 43 Constraint... 187 Figure 10.3: Post-Dispatch of 1500 MW Generation Path 43 Constraint... 188 Figure 10.4: Post-Dispatch of Facility Loading Adder Path 43 Constraint... 189 Figure 10.5: Post-Dispatch of Facility Loading Adder with mitigation Path 43 Constraint... 190 Figure 10.6: Traditional Power Flow Dispatch Path 43 Constraint... 191 Figure 10.7: Traditional Power Flow Dispatch with Mitigation Path 43 Constraint... 192 iv

Generator Interconnection and Deliverability Study Methodology List of Tables Table II-1: Resource Dispatch Assumptions... 21 Table 1.1: Whirlwind 500/230kV Transformer Flows Deliverability Methodology... 27 Table 1.2: Whirlwind 500/230kV Transformer Flows Traditional Power Flow Approach... 28 Table 1.3: Grouping and Dispatch of Generators behind Whirlwind Transformers... 30 Table 2.1: Borrego Area Line Flows Deliverability Methodology... 35 Table 2.2: Borrego Area Line Flows Traditional Power Flow Approach... 35 Table 2.3: Grouping and Dispatch of Generators in Borrego Area... 37 Table 2.4: Grouping and Dispatch of Generators in Borrego Area Traditional Power Flow Approach... 37 Table 3.1: ECO 230/138 kv Transformer Flows Deliverability Methodology... 42 Table 3.2: ECO 230/138 kv Transformer Flows Off-Peak Study... 42 Table 3.3: Grouping and Dispatch of Generators in ECO/BUE Area... 44 Table 3.4: Dispatch of Generators in ECO/BUE Area Off-Peak Study... 45 Table 4.1: Imports and ETC Relevant to North of Lugo Constraints... 51 Table 4.2: Potential Overloads as North of Lugo Constraints... 51 Table 4.3: Kramer Lugo 230 kv No.1 & 2 Line Flows Deliverability Methodology... 51 Table 4.4: Kramer Lugo 230 kv No.1 & 2 Line Flow with Kramer Llano 500kV Upgrades... 52 Table 4.5: Grouping and Dispatch of Generators behind Kramer Lugo Constraint... 54 Table 5.1: Imports and ETC Relevant to PG&E North Study Area... 63 Table 5.2: Grouping and Dispatch of Generators behind the Vaca Dixon WindUnit_POI Constraint... 65 Table 5.3: Flow on the Vaca Dixon WindUnit_POI #3 line... 69 Table 5.4: Comparison of Available MW (Name Plate, Pmax) and Dispatched MW... 69 Table 5.5: Comparison of the deliverability and reliability study impact due to the WindUnit POI-Vaca Dixon #1 & #2 contingency... 70 Table 6.1: Imports and ETC Relevant to Fresno Study Area... 79 Table 6.2: Grouping and Dispatch of Generators behind Panoche-Dos Amigos Flow... 81 Table 6.3: Total Dispatch for Units in the 5% Circle versus Total Nameplate Values... 87 Table 6.4: Deliverability and Traditional Power Flow Loading Levels... 87 Table 7.1: Imports and ETC Relevant to Desert Area Constraints... 95 Table 7.2: Potential Overloads as Desert Area Constraints... 96 Table 7.3: Grouping and Dispatch of Generators behind by Lugo Victorville Constraint... 98 Table 7.4 Facility Load Adder (FLA) Calculation... 104 Table 7.5: Lugo Victorville Line Flow Deliverability Methodology... 107 Table 8.1: Imports and ETC Relevant to Desert Area Constraints... 121 Table 8.2: Potential Overloads as Desert Area Constraints... 122 Table 8.3: Grouping and Dispatch of Generators behind Lugo Eldorado Constraint... 124 Table 8.4: Facility Loading Adder (FLA) Calculation... 129 Table 8.5: Lugo - Eldorado Line Flow Deliverability Methodology... 131 Table 8.6: Lugo - Eldorado Line Flow with Upgrades... 131 Table 9.1: Imports and ETC Relevant to South of Vincent Constraint... 149 Table 9.2: Potential South of Vincent Overload... 149 Table 9.3: Grouping and Dispatch of Generators Constrained by Vincent 500/230kV Transformer Overload... 151 Table 9.4: Facility Loading Adder (FLA) Calculation... 163 Table 9.5: Vincent Transformer Bank Flow Deliverability Methodology... 165 Table 9.6: Generators Removed to Reduce Vincent Transformer Bank Loading... 165 v

Generator Interconnection and Deliverability Study Methodology Table 10.1: Imports and ETC Relevant to SDG&E Area Study... 178 Table 10.2: Potential Overload on Path 43... 178 Table 10.3 Facility Load Adder (FLA) Calculation... 180 Table 10.4: Path 43 Flow Deliverability Methodology... 181 Table 10.5: Path 43 Flow Traditional Study Methodology... 181 Table 10.6: Grouping and Dispatch of Generators behind Path 43 Constraint... 183 vi

Generator Interconnection and Deliverability Study Methodology Introduction Deliverability is an essential element of any resource adequacy requirement. Specifically, Load Serving Entities (LSEs) must be able to show that the supplies they intend to procure to meet their load requirements can be delivered to load when needed. Otherwise, such resources are of little, if any, value for the purposes of resource adequacy. The California Public Utilities Commission (CPUC) requires LSEs to demonstrate the deliverability of the resources they procure in both their annual resource plans and their longterm resource plans. An effective deliverability assessment is essential in short-term resources plans so that the LSEs will be able to count their resources to determine whether they satisfy the Commission s planning reserve margin. For long-term procurement planning, such an assessment additionally ensures that LSEs identify capacity needs that may be met by deliverable generation, or demand response but which require forward commitment to implement the desired solution, thus providing for an appropriate coordination between resource planning and transmission planning. The ISO deliverability methodology is the result of much stakeholder discussion. It was developed through a number of stakeholder meetings and conference calls during 2004 through 2006. It has been utilized since the serial group for ISO generation interconnection studies. However, for the serial group interconnection studies performed between 2006 and through 2008 the PTOs performed power flow studies and identified delivery transmission upgrades. The deliverability assessment was then performed on cases with those upgrades already modeled, so there were no major upgrades identified as needed by the deliverability assessment beyond what the PTOs had already identified. Starting with the Transition Cluster interconnection study in 2008, the deliverability study was used to identify all delivery network upgrades. The PTOs still identified upgrades beyond what the ISO identified but the ISO determined that congestion management could be used in lieu of upgrades identified by the PTOs but not required by the deliverability assessment. In both the serial interconnection studies and the Transition Cluster the deliverability study methodology generally identified the need for fewer upgrades than traditional study methodologies. However with the amount of generation in the queue five times the amount expected to actually be built, we still see significant transmission upgrades using the deliverability assessment methodology. The methodology relies on sophisticated generation dispatch tools and does not rely on a single snapshot power flow typically used in traditional methodologies, so it seems to be a mystery to some stakeholders. Some stakeholders seem to have attributed the cause of high transmission upgrade costs to the deliverability study methodology and expressed a need for the ISO to provide more detailed information on the methodology. This paper offers a detailed explanation of the ISO deliverability study methodology, and includes numerous detailed examples of the methodology being applied. As demonstrated by these examples, congestion management has been applied system wide as means to mitigate overloads identified under more stressed operating conditions than the deliverability assessment and SPS are used extensively to mitigate contingency overloads as long as the SPS design complies with the ISO new SPS guideline. This paper consists of three sections: Section One is background information on the basis for the methodology and an overview of the methodology. In this section references are provided 1

Generator Interconnection and Deliverability Study Methodology from FERC Order 2003 and the CPUC resource adequacy proceedings that highlight the basis for the methodology. This section also includes a description of the ISO generation interconnection reliability assessment that is performed along with the deliverability assessment. In addition to going over the generation deliverability assessment, this section will also briefly go over the import deliverability assessment. Section Two is a complete description of the methodology, and Section Three provides examples of the methodology being applied. 2

Generator Interconnection and Deliverability Study Methodology Section One: Background Information on the Basis for the Methodology and an Overview of the Methodology Background As part of developing its proposal to comply with FERC s Order No. 2003 regarding the interconnection of new generating facilities, the ISO developed and proposed to FERC a deliverability test. The purpose was to assess the deliverability of new generation to serve load on the ISO s system. Experience at that time indicated that while California had added needed new generating capacity to the system, not all of that capacity was deliverable to load on the system because of the presence of transmission constraints. Therefore, although not requiring all new generation to be deliverable, the ISO proposed in its Order 2003 compliance filing to assess deliverability for those generators seeking to count for resource adequacy so that the sponsors of new generation projects could deliver the output of the new plants to the aggregate of load for resource adequacy counting purposes. During the stakeholder process developing the ISO deliverability test, a baseline analysis was performed by the ISO to demonstrate to stakeholders, in full detail, the test that would be conducted as part of this interconnection process. The deliverability test verifies a generating facility s ability to deliver its energy to load on the ISO Controlled Grid under peak load conditions and identifies the required Network Upgrades to enable the generating facility to deliver its full output to load on the ISO Controlled Grid based on specified study assumptions. That is, a generating facility s interconnection is studied with the ISO Controlled Grid at peak load, under a variety of severely stressed conditions to determine whether, with the generating facility at full output, the aggregate of generation in the local area can be delivered to the aggregate of load on the ISO Controlled Grid, consistent with the ISO s reliability criteria and procedures. (This definition for deliverability comes from the FERC interconnection order, and this methodology for assessing deliverability has been developed from consultation with PJM officials about their practices.) In addition, the ISO methodology, based on guidance in FERC Order 2003, ensures that the deliverability of a new resource is assessed on the same basis as all other existing resources interconnected to the ISO Controlled Grid. Because the deliverability assessment focuses on the deliverability of generation capacity when the need for capacity is the greatest (i.e. peak load conditions), it does not ensure that a particular generation facility will not experience congestion during other operating periods. Furthermore, as will be shown in the example study results, the deliverability test does not ensure that there will not be congestion during certain low probability, high generation dispatch conditions during the summer peak load period. Specific References from FERC Order 2003 and CPUC Resource Adequacy Proceeding The following references from FERC Order 2003 and the CPUC resource adequacy proceeding highlight the basis for the methodology. 3

Generator Interconnection and Deliverability Study Methodology FERC Order 2003 requires that two interconnection service options are offered: Energy Resource Interconnection Service (ERIS) and Network Resource Interconnection Service (NRIS). ERIS generation can compete in the ISO market against other generators. Paragraph 753 of FERC Order 2003 describes ERIS: ERIS would allow the Interconnection Customer to connect its Generating Facility to the Transmission System and be eligible to deliver its output using the existing capacity of the Transmission System on an "as available" basis. In an area with a bid-based energy market ERIS would allow the Interconnection Customer to place a bid to sell into the market and the Generating Facility would be dispatched if the bid is accepted. The ISO Tariff refers to this type of generation as Energy Only Deliverability Status (EODS) generation. EODS generation has a net qualifying capacity (NQC) for resource adequacy planning of zero. In other words EODS generation cannot be counted to meet the 115% planning reserve margin requirement. NRIS generation meets generation capacity planning requirements while satisfying regional reliability criteria 1. Paragraph 769 of FERC order 2003 describes NRIS: Network Upgrades required under NRIS integrate the Generating Facility into the Transmission System in a manner that ensures that aggregate generation can meet aggregate load while satisfying regional reliability criteria and generation capacity planning requirements. The ISO Tariff refers to this type of generation as Full Capacity Deliverability Status (FCDS) generation. FCDS generation meets generation capacity planning requirements while satisfying regional reliability criteria. FCDS generation can be counted to meet the 115% planning reserve requirement. CPUC Decision D.04-10-035 adopted the CAISO s deliverability methodology to determine deliverability of qualifying resources. The CAISO published a preliminary deliverability baseline analysis report and conducted a stakeholder meeting in May 2005, after the Resource Adequacy Proceeding Phase 2 workshops were concluded 2. During the deliverability study, EODS generation is turned off, so that it does not impact the deliverability of full capacity generation. Some people have argued that it is not reasonable to dispatch the system with only FCDS resources. However these stakeholders are missing the point of the resource adequacy requirement. The ISO is required to be able to keep the lights on if resource adequacy resources were the only ones available, because by definition we can t count on the EODS resources even if these EODS resources have operated in the past instead of nearby FCDS resources. In most cases, generators choose to be EODS because they don t want to pay for transmission upgrades. As a result, EODS resources can only be reliably dispatched when they displace full capacity resources. If we counted on EODS resources and all FCDS resources for resource adequacy planning purposes we would not be able to dispatch both types of resources at the same time, and therefore we would not have a dependable resource supply in our resource plans. 1 FERC Order 2003 Paragraphs 768, 769 and Appendix C 2 CPUC Decision D.05-10-042 4

Generator Interconnection and Deliverability Study Methodology Although the transmission impacts of EODS generation and FCDS generation are studied much differently, Order 2003 requires that new FCDS generation is studied the same as all existing FCDS generation has been studied, as described in FERC Order 2003 Paragraph 768: NRIS entitles the Generating Facility to be treated in the same manner as the Transmission Provider's own resources for purposes of assessing whether aggregate supply is sufficient to meet aggregate load within the Transmission Provider's Control Area, or other area customarily used for generation capacity planning. In 2005 the ISO demonstrated through a stakeholder process that all existing resources could meet its deliverability assessment test methodology, except in a couple of locations where minor upgrades such as wave trap replacements were required. Order 2003 also requires that the transmission interconnection studies of FCDS generation are based on NERC Reliability Standards. The pro forma LGIP provided in FERC order 2003 describes the interconnection study to establish NRIS for a new generator as being based on peak load conditions and a variety of severely stressed conditions with the new generator and generators in the local area at full output. These assumptions are to ensure that the new generator can be delivered to the aggregate of load consistent with the applicable reliability criteria. In FERC Order 2003, Appendix C LGIP Section 3.2.2.2 states the following: The Interconnection Study for NRIS shall assure that Large Generating Facility's interconnection is studied at peak load, under a variety of severely stressed conditions, to determine whether, with the Large Generating Facility at full output, the aggregate of generation in the local area can be delivered to the aggregate of load on the Transmission Provider s Transmission System, consistent with the Transmission Provider s reliability criteria and procedures. Specific References from NERC Reliability Standards Order 2003 requires that the transmission interconnection studies of FCDS generation are based on NERC Reliability Standards. Interconnection studies of FCDS generation include both a reliability assessment and a deliverability assessment. The reliability assessment is performed on both the EODS and FCDS generation, but the deliverability assessment is only performed on the FCDS generation. This section provides several references to the NERC reliability standards that apply to interconnection studies of both EODS and FCDS generation. The references describe the scope of the studies that must be performed. When reliability concerns are identified during the studies, corresponding mitigation plans must be identified. If the redispatch of generation through the ISO market (also known as congestion management) is determined to be feasible as a mechanism to mitigate the identified reliability concern then congestion management may be the identified mitigation plan. When congestion management is identified as feasible for EODS generation then it is generally the recommended mitigation. As described earlier, the deliverability methodology only addresses certain dispatch conditions during summer peak load conditions. If reliability concerns are identified during non-summer peak load conditions, or under generation dispatch conditions beyond those specified in the deliverability methodology, then congestion management is recommended as the mitigation, when it is feasible, for FCDS generation. NERC Reliability Standard FAC 002 Coordination of Plans for New Generation, Transmission, and End-User Facilities is an applicable reliability standard for generation interconnection studies. It requires steady-state, short-circuit, and dynamics studies as necessary to evaluate 5

Generator Interconnection and Deliverability Study Methodology system performance under both normal and contingency conditions in accordance with Reliability Standards TPL-001, TPL-002, and TPL-003. NERC Reliability Standard TPL 002 requires single contingency analysis, and NERC Reliability Standard TPL 003 requires common mode N-2 contingency analysis and bus outages. NERC Reliability Standard FAC 010 System Operating Limits Methodology for the Planning Horizon is also an applicable reliability standard for generation interconnection studies. It requires an analysis starting with all facilities in service and following any of the multiple contingencies identified in Reliability Standard TPL-003 the system shall demonstrate transient, dynamic and voltage stability; all facilities shall be operating within their facility ratings and within their thermal, voltage and stability limits; and cascading or uncontrolled separation shall not occur. NERC Reliability Standard TPL 003 requires common mode N-2 contingency analysis and bus outages. The system operating limits established in the planning horizon must be observed in generation deliverability studies. Mitigation of NERC Reliability Standard Compliance Concerns When reliability concerns are identified during the studies, corresponding mitigation plans must be identified. If the redispatch of generation through the ISO market (also known as congestion management) is determined to be feasible as a mechanism to mitigate the identified reliability concern then congestion management may be the identified mitigation plan. When congestion management is identified as feasible for EODS generation then it is generally the recommended mitigation. As we saw, Order 2003 intended EODS generation to compete with existing generation in order to get access to the transmission system. Therefore the use of congestion management to mitigate delivery constraints identified in EODS interconnection studies is expected. This is because EODS generation is expected to need to compete against generation in the local area to get access to the transmission system under most stressed system conditions. On the other hand, Order 2003 required that FCDS generation must be deliverable without displacing existing full capacity generation under summer peak load conditions. Therefore, FCDS generation must be deliverable along with the other FCDS generation in the local area during summer peak load conditions under a variety of severely stressed system conditions. As described earlier, the deliverability methodology only addresses certain dispatch conditions during summer peak load conditions. If reliability concerns are identified during non-summer peak load conditions, or under generation dispatch conditions beyond those specified in the deliverability methodology, then congestion management is recommended as the mitigation, when it is feasible, for FCDS generation. In EODS and FCDS interconnection studies the ISO and PTO perform short circuit and stability studies. We also perform power flow analysis to identify the need for upgrades if congestion management would not sufficiently mitigate the identified problem. In the FCDS interconnection studies we also perform a deliverability assessment. In addition to EODS and FCDS, the ISO also offers Partial Capacity Deliverability Status (PCDS) to generation. However for study purposes we can subdivide a partially deliverable generation project into an FCDS portion and an EODS portion and then study each portion accordingly. The interconnection customer is allowed to choose which level of service they want. A generation deliverability assessment will identify for the interconnection customer the required network upgrades needed for FCDS or PCDS. 6

Generator Interconnection and Deliverability Study Methodology Overview of the Methodology As discussed earlier, in 2004 and 2005 the ISO proposed the generation deliverability methodology to CPUC for Resource Adequacy purposes and to FERC for generator interconnection purposes. In 2005 the ISO completed a baseline generation deliverability assessment of all generation expected to be in operation during summer 2006. Also in 2005 the CPUC and FERC generally approved methodology for use in Resource Adequacy and Generator Interconnection processes, and in 2006 the ISO began applying deliverability methodology to new generator projects in the generator interconnection queue. The baseline generation deliverability assessment confirmed, using the ISO deliverability methodology that existing generating units in the ISO balancing area together with historical summer peak imports levels were deliverable. This study validated the methodology in an open stakeholder process. It also established evidence that the ISO applies the same methodology to both existing and planned generation. The methodology is based on the premise that FCDS resources within a given sub-area must be able to be exported to other parts of the balancing area experiencing a resource shortage due to forced generation outages. As stated earlier, this deliverability methodology is based on the PJM methodology and this fundamental concept is from the PJM methodology. Transmission Deliverability Analysis during a Resource Shortage Condition The purpose of the deliverability assessment methodology is to test the ability of the transmission system to export resources within a given sub-area to other parts of the balancing area experiencing a resource shortage. This test is a complex analysis of the transmission system under a variety of severely stressed generation dispatch conditions under summer peak load conditions when a resource shortage is most likely. The analysis is complex because there are roughly 25,000 Miles of transmission lines and hundreds of transmission transformers networked together to reliably deliver about 1000 geographically dispersed generating units to geographically dispersed load or to potentially constrain the deliverability of this generation, resulting in unserved customers. Figures I-1 and I-2 show the electric transmission network and the locations of the numerous electric generation resources in California. The loading on the transmission network depends entirely on the availability and dispatch of the generation resources. Under certain combinations of generation availability and dispatch the transmission system can be overloaded and the only way to prevent a transmission equipment failure is to reduce the dispatch of some of the generation. In a resource shortage scenario, if the generation must be reduced then some of the load cannot be served. Power system computer models of the transmission and generation system in Figures I-1 and I-2 are utilized to test numerous generation availability and dispatch scenarios during resource shortage conditions and the capability of the transmission system to accommodate these scenarios. 7

Generator Interconnection and Deliverability Study Methodology Transmission Lines in California Figure I-1: Electric transmission network in California Power Plants in California Figure I-2: Electric power plant locations in California 8

Generator Interconnection and Deliverability Study Methodology Resource shortage conditions are typically caused by a number of generation equipment mechanical failures on several large generating units or fuel interruptions during summer peak load conditions. During resource shortage conditions, all available generation capacity in the ISO balancing area is dispatched to avoid interrupting customer service. Figure I-3 depicts a typical resource shortage scenario. In the scenario shown, all generation in Pocket 1 is available and needs to be dispatched at full output to serve all customers in the ISO balancing area. Figure I-3: Depiction of resource shortage Scenario 1 in California 9

Generator Interconnection and Deliverability Study Methodology Figure I-4: Depiction of resource shortage Scenario 2 in California Figure I-4 shows another typical resource shortage scenario in California. In Scenario 2, all generation in Pocket 2 is available and needs to be dispatched at full output to serve all customers in the CAISO control area. The deliverability assessment methodology is designed to ensure that available generation in the various generation pockets, for all reasonable generation availability scenarios, will not be constrained by transmission limitations during resource shortages. One additional point is that, generally, the exact location of the set of generating unit outages, graphically represented by the small black squares, does not significantly change the results of the deliverability analysis of the generation pocket. The units forced out in Scenarios 1 and 2 are outside of the generation pocket study area, so their status and dispatch levels, in aggregate, do not significantly impact the results of the analysis within the study area. This is an important observation because there are literally hundreds of thousands of generation forced outage scenarios that can result in a resource shortage conditions. However, all of these scenarios can generally be represented, in a power system model, by evenly distributing the unavailable generation amount across all generating units in the ISO balancing area. Then, using that power system model, generation within a particular generation pocket can be tested for deliverability during all potential resource shortage conditions by maximizing the output of 10

Generator Interconnection and Deliverability Study Methodology the available generation within the generation pocket. This fundamental technique was learned from the PJM generation deliverability methodology. Overview of the Deliverability Analysis Testing Process The previous section describes the general approach for the deliverability methodology. This section builds on the concepts introduced in the previous section and describes additional concepts that need to be understood in order to understand the ISO deliverability methodology. At a high level, the test procedure can be thought of as the following three basic steps. First we build the initial power flow base case. Second, we utilize a commercially available software tool to perform generation sensitivity analysis to identify potentially limited generation pockets. At the most granular level, the sensitivity analysis identifies the exact generation facilities that have the highest flow impact on a particular transmission facility with all other facilities in-service and during forced outages of other facilities. Then the generation with the highest flow impact on that facility is increased a nominal amount to assess the potential for that facility to be overloaded under stressed system conditions. All ISO controlled facilities are analyzed to determine if they are limiting the deliverability of generation within the ISO deliverability methodology parameters. Initial Base Case Dispatch As described above, all generation is dispatched in the initial base case at close to maximum dependable capacity. The selected percentage dispatch below maximum capacity considers the average forced outage rates of the generators, spinning reserve, and unexpected retirement of generation capacity across the system. For the cluster studies we have been dispatching all generation at 80% of maximum dependable capacity. Because we are modeling a resource shortage scenario, it is assumed that all available generation is being dispatched, and due to the shortage condition, the incremental dispatch cost of generation is not affecting the dispatch. For the cluster studies, the amount of generation in the interconnection queue far exceeds the amount needed to achieve a load and resource balance. Therefore the queued generation is organized into geographic areas, and five to ten base cases are built with each case designed to focus on a particular geographic area. Then the queued generation in these areas is dispatched similar to the existing generation (e.g. 80% of dependable capacity). Identification of Generation Pockets Associated with Individual Transmission Facility Constraints As described above, each transmission line and transformer is analyzed individually starting from the initial base case dispatch. A study group is established for each line and transformer that includes all generation with a 5% distribution factor or greater on the particular line or transformer. The 5% distribution factor threshold is also used by PJM in their deliverability analysis methodology. For each analyzed facility, an electrical circle is drawn which includes all units that have a 5% or greater distribution factor (DFAX) on the facility being analyzed. The 5% Circle can also be referred to as the study group for the particular facility being analyzed. Capacity generation dispatch inside the study group is increased to determine the loading on the line or transformer under stressed system conditions. Generation outside the study group is proportionally decreased to maintain the balance between loads and resources. This process is intended to test the ability of available resources inside of the study group to be dispatched at full output when various resources across the ISO system are unavailable during a resource 11

Generator Interconnection and Deliverability Study Methodology shortage condition. Figure I-5 shows a sample system and the creation of a study group around the Gregg-Borden line. The distribution factor for each generator is shown and the dashed line is drawn around the generators with a 5% distribution factor or greater to show the generation pocket boundary. Note that increasing Helms output 100 MW and scaling the remaining generation in the ISO balancing area down by 100 MW will increase the flow on the line by 23 MW. Figure I-5: Depiction of a Study Group Based on the 5% Distribution Factor Threshold Generation Dispatch inside the Study Group The outputs of capacity units in the 5% Circle study group are increased starting with units with the largest impact on the transmission facility. The number of units to be increased within a group is limited to an amount of generation that can be reasonably expected to be simultaneously available, and the likelihood of all of the units within a group being available at the same time becomes smaller as the number of units in the group increases. The objective of the ISO deliverability methodology is to ensure that roughly 80% of the time, the transmission system will not constrain the output of generation in a study group during a resource shortage condition. The cumulative availability of twenty units with a 7.5% forced outage rate would be 21%. Therefore, no more than twenty units are increased to their maximum output within a study group. All remaining generation within the ISO balancing area is proportionally displaced, to maintain a load and resource balance. The amount of generation increased also needs to be limited because decreasing the remaining generation can cause problems that are more closely related to a generation deficiency in a load pocket rather than a generation pocket deliverability problem. Therefore, no more than a 1500 MW increment of generation is increased within a study group. 12

Generator Interconnection and Deliverability Study Methodology For groups where the 20 units with the highest impact on the facility can be increased more than 1500 MW, the impact of the remaining amount of generation to be increased will be considered using a Facility Loading Adder. The Facility Loading Adder is calculated by taking the remaining MW amount available from the 20 units with the highest impact times the DFAX for each unit. An equivalent MW amount of generation with negative DFAXs will also be included in the Facility Loading Adder, up to 20 units. Negative Facility Loading Adders are set to zero. Some of the examples in Section Three of the report show examples of the Facility Loading Adder. Import Assumptions California is now, and will likely remain, dependent on a significant level of imports to satisfy its energy and resource requirements. Therefore, it is likely that as part of fulfilling their obligation to procure sufficient resources (reserves) in the forward market to serve their respective loads, the LSEs will contract with out-of-state resources. This is appropriate and necessary. The ability to rely on imports to satisfy reserve requirements is entirely dependent on the deliverability of such out-of-state resources to and from the intertie points between the ISO s system and the neighboring systems. While the existing system may be able to satisfy the procurement plans of any one LSE, it likely will not be able to transmit the sum of LSEs needs. Each LSE may well plan to rely on the same potentially constrained transmission paths to deliver their out-of-state resources. Therefore, the transmission system should be checked to make sure that simultaneous imports can be accommodated. When relying on imports to serve load, each LSE should be required to ensure that they have assessed the deliverability of such resources from the tie point to load on the ISO s system. Transmission constraints can impact the simultaneous deliverability of imports and internal generation. As a result, the interaction between the deliverability of imports and the deliverability of generation needs to be examined. The ISO generation deliverability assessment includes, as an input assumption, the amount of imports and existing transmission contract related encumbrances electrically flowing over the ISO Controlled Grid. Whatever import capacity is available to LSEs for resource adequacy planning purposes is also the basis for the import assumptions in the internal generation deliverability analysis. Historical import information is the basis for determining the amount of import levels to be allocated to LSEs. In addition to using historical data, existing transmission contract information is also utilized. It is assumed that the entities that have contracted for the transmission capacity are already relying on this import capability in their resource plans, so this transmission is not reallocated. Generation Capacity Study Assumptions Existing generation dependable capacity is modeled in the deliverability study base cases based on their Net Qualifying Capacity posted on ISO website. The NQC is determined based on a methodology that generally sets the dependable capability of a generator close to its nameplate capability. However, for intermittent generation the NQC is based on its production level during summer peak load hours and therefore the NQC of intermittent generation can be substantially lower than nameplate capability. The qualifying capacity of intermittent generation is calculated based on a 70% exceedance methodology. A production duration curve is created for each intermittent generation project (e.g. wind and solar generation). An example curve is 13

Generator Interconnection and Deliverability Study Methodology shown in Figure I-6. From this curve one can identify the production level that is exceeded 70% of the time during the 100 hours included in the data. This is done for each generation project individually. Figure I-6: Example Production Duration Curve Showing 70% Exceedance Level However, a diversity adder is then added to the 70% exceedance level calculated for each project by itself. The diversity adder is calculated by adding the production of all wind and solar generation across the state for each summer peak load hour. Then the aggregate 70 % exceedance level is calculated for the entire state. The individual 70% exceedance levels are adjusted upwards so that the sum of NQC values of all intermittent generation is equal to the 70% exceedance value that was calculated for the entire state. The diversity adder captures the diversity value of intermittent generation across the state. Due to the nature of wind patterns, there can be strong winds in Southern California and no wind in Northern California, or it can be the other way around. Aggregating the intermittent generation in Northern California and Southern California results in a more reliable wind resource. However, the high wind production levels must be deliverable or this value is lost. Figure I-7 shows a simple diversity adder calculation example with two 100 MW wind plants. The blue and red curves are the production duration curve for Wind Plants 1 and 2 respectively, and the green curve is their combined production duration curve. Wind Plants 1 and 2 have a 70% exceedance level of 8 MW and 11 MW respectively. However, their combined 70 % exceedance level is 33 MW. Therefore each plant is given a diversity adder of 7 MW. As a result Wind Plant 1 and 2 have an NQC of 15 MW and 18 MW. 14

Generator Interconnection and Deliverability Study Methodology Figure I-7: Example Production Duration Curve Showing Combined 70% Exceedance Level An important consideration is that the diversity adder results in counting production levels from Wind Plants 1 and 2 that are higher than their NQC levels. Figure I-8 shows blue and red lines representing 24 hours, during the summer peak load period, of simultaneous production levels for Wind Plants 1 and 2 respectively. Hour number 10 in the Figure is highlighted in yellow because that hour is counted in the 70 % exceedance calculation for the combined output of both wind plants. The important point is that hour number 10 includes a production level from one of the wind plants that is about 33 MW which is about twice its NQC level. If the wind generation from Wind Plant 1 were constrained by the transmission in hour number 10 then the diversity benefit of the wind between Wind Plant 1 and 2 would be lost for that hour. Figure I-8: Example Production Curve Showing Production Levels Counted by the 70% Exceedance Level Calculation Another important consideration is that the 70% exceedance value methodology results in counting resources that are not available or derated 30% of the time. A typical resource is not available or derated about 5% to 10% of the time. However, as can be seen by Figure I-8 a 15