Preliminary Planning Study Central California Clean Energy Transmission Project

Study Plan

Version 1.2 February 29, 2008

Stakeholder Group Study

Table of Contents Study Objective...... 3 Potential Alternatives ...... 3 Alt-1: Status Quo...... 3 Alt-2: Central California Clean Transmission Project (C3ETP)...... 3 Alt-3: Same as Alt-2, except building a Midway – E2 Single Circuit Tower Line (SCTL) ...... 5 Alt-4: Build a Whirlwind – San Joaquin - E2 500 kV DCTL...... 5 Alt-5: Build a Midway – E2 230 kV DCTL...... 5 Alt-6: Build a new PG&E and SCE Big Creek 230 kV Tie...... 6 Alt-7: Build a Midway – McCall – E2 230 kV DCTL...... 6 Alt-8: Build a Gates – Gregg 230 kV DCTL ...... 6 Alt-9: Raisin City Switching Station...... 7 Alt-10: New Generation...... 7 Reliability Assessments...... 8 1. Study Base Cases: ...... 8 2. Renewable Resources...... 10 3. 500 and 230 kV Contingencies ...... 10 4. Sensitivity Studies:...... 10 5. Study Criteria...... 11 6. Study Scope...... 11 7. Methodology for Reliability Analysis...... 11 a. Load Serving Capability to the Fresno and Yosemite Area...... 11 b. Transmission Capacity for Supporting Helms Pumping Operation...... 12 c. Import Capability from southern California...... 12 Economic Assessments ...... 13 1. Methodology for Economic Analysis ...... 13 2. Study Base Cases for Economic Analysis...... 14 Preliminary Study Schedule...... 16 Attachment 1 One Line Diagram ...... 17 Attachment 2 Transmission Facilities Included in Reliability Assessment Base Cases ...31 Attachment 3 Potential New Generation in the Greater Fresno Area ...... 35 Attachment 4 Renewable Resource List Modeled in 2022 Summer Peak Base Case).....37 Attachment 5 List of Old Thermal Generation Plants (May be Modeled Off-line)...... 40 Attachment 6 List of Contingencies...... 44 Attachment 7 Reliability Criteria ...... 47

Study Objective The purpose of this study is to evaluate further the benefits of potential alternatives that could meet the following major long-term (at least 20 years) goals in order to identify the least cost-highest benefit alternative that achieves these goals:

1. Support California’s Renewable Portfolio Standard (RPS) target(s) by increasing the ability of Central and Northern California to access renewable resources in southern California; 2. Improve transmission reliability and serve load growth in the Fresno and Yosemite areas by allowing sufficient access to generation to meet local demand for at least the next twenty (20) years; 3. Maximize asset utilization by providing support for all three units at Helms Pumped Storage Plant (PSP) to operate in the pumping mode using excess off- peak energy; 4. Provide opportunity for future expansion that can be integrated with the California regional bulk transmission system, in order to allow increased access to renewable resources and other resources, including greenhouse-gas neutral resources, in Southern California in order to serve load growth in the San Francisco Bay Area, Sacramento Valley Area, and other areas. Potential Alternatives

Alt-1: Status Quo

Alt-2: Central California Clean Transmission Project (C3ETP) The Central California Clean Transmission Project (C3ETP) would build a new 500 kV Double Circuit Tower Line (DCTL) from Midway to a new 500/230 kV Substation (E2) between Gregg substation and Helms PSP. See Fig 1. This project includes the following facilities:

1. Build a 500 kV DCTL strung with two 2300 kcmil AAL conductors (bundled), 2. Build a new 500 kV Substation (E2) with one 500/230 kV 1,120 MVA transformer bank, 3. Loop the Helms – Gregg #1 and #2 230 kV lines into the E2 Substation, 4. Build 500 kV line terminations at Midway and E2, and 5. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study.

This alternative will mainly consider two alternative corridors; an east corridor and a west corridor.

East Corridor: The potential route on the east corridor (or east route, which is estimated to be about 141 miles) is easterly of the Southern California Edison’s Big Creek 230 kV corridor and

terminates at the new E2 Substation at where it crosses of the Helms-Gregg 230 kV lines. Because it would run parallel to SCE’s Big Creek – Magunden 230 kV lines for part of the distance, the east route of the C3ET Project could potentially use SCE’s existing access roads and could also support SCE’s future expansion plans to serve SCE’s customers in the Big Creek area. SCE’s future expansions alternatives, which could take advantage of the east route should the associated CPCN be granted are as follows: Alt-2A: Build a San Joaquin 500 kV Substation looping into one of the Midway – E2 500 kV DCTL Alt-2A is a future expansion alternative of the C3ET Project. This alternative would allow SCE to build the following facilities to serve SCE’s customers in the Big Creek area: 1. A new SCE 500/230 kV Substation (currently named “S2”) with two 500/230-kV 1,120 MVA transformer banks in the vicinity of the SCE’s San Joaquin Valley load center 2. Loop one Midway-E2 500-kV line into S2 Substation 3. Loop three existing Big Creek Corridor 230-kV transmission lines into the new S2 Substation (i.e., Big Creek 4-Springville 230-kV, Big Creek 3-Rector No. 2 230-kV, and Rector-Springville 230-kV)

Alt-2B: Same as Alt-2A, except also building a Magunden 500 kV Substation looping into the second Midway – E2 500 kV DCTL and a new Magunden – Whirlwind 500 kV SCTL Alt-2B is also a future expansion alternative of the C3ET Project. This alternative is same as Alt-2A, except it would allow SCE to build the following additional facilities to serve SCE’s customers in the Big Creek area: 1. Build a new SCE 500/230-kV Substation (S3 or “Magunden 500-kV”) with one 500/230-kV 1,120 MVA transformer bank in the general vicinity of the existing SCE Magunden 230-kV Substation, 2. Loop the second Midway – E2 500 kV line into S3 Substation by building a 500 kV DCTL from the C3ET Project to S3 Substation, 3. Construct a Whirlwind- S3 500 kV SCTL 4. Connect the S3 substation 230-kV bus to the existing Magunden 230-kV bus via short segment of 230-kV DCTL (“jumper”)

Alt-2C: Same as Alt-2A, except also upgrade PG&E-own section of the Midway – Vincent #3 500 kV line

Alt-2C is also a future expansion alternative of the C3ET Project. This alternative would include upgrading by PG&E of the northern section of the Midway – Vincent #3 500 kV line (owned by PG&E) to improve transfer capability on Path 26 in both directions; Importing additional renewable resources from southern California and increasing power transfer to southern California.

West Corridor: The west corridor of the C3ET project runs west of the existing Los Banos – Midway 500 kV line corridor, then crosses the valley at a point north of Avenal to the vicinity of Gregg Substation (about 147 miles) and then extends to and terminates at the new E2 Substation (an additional 30 miles). As such, a route in the west corridor (west route) would be too far away from the SCE’s Big Creek area to support any SCE’s future expansion alternatives described above to serve customers in the Big Creek area.

Alt-3: Same as Alt-2A, except building a Midway – E2 Single Circuit Tower Line (SCTL) This alternative will build a Midway – E2 500 kV SCTL with 50% series compensation.

Alt-4: Build a Whirlwind – San Joaquin - E2 500 kV DCTL Whirlwind is a SCE proposed new 500/230 kV substation in the Tehachapi area of southern California (formerly known as Sub-5). This alternative is similar to the Alt-2A, except this alternative would bypass Midway Substation and terminate the 500 kV DCTL at Whirlwind Substation. The alternative would include the following facilities:

1. Build a 500 kV Double Circuit Tower Line from Whirlwind to E2 with two 2300 kcmil AAL conductors (bundled), 2. Build a new 500 kV Substation (E2) with one 500/230 kV 1,120 MVA transformer banks, 3. Loop the Helms – Gregg #1 and #2 230 kV lines into the E2 Substation, 4. Build a 500 kV line termination for each circuit at Whirlwind and E2, and 5. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study. 6. Build a new SCE 500/230 kV Substation (S2) with two 500/230 kV 1,120 MVA transformer banks in the vicinity of the SCE SJV load center 7. Loop one Whirlwind – E2 500 kV line into S2 Substation, 8. Loop three existing Big Creek Corridor 230-kV transmission lines into the new S2 Substation (i.e. Big Creek 4-Springville 230-kV, Big Creek 3-Rector No. 2 230-kV, and Rector-Springville 230-kV)

Alt-5: Build a Midway – E2 230 kV DCTL This alternative is to build a Midway – E2 230 kV DCTL. This alternative includes the following facilities:

1. Build a new 230 kV switching station (E2), 2. Build a Midway – E2 230 kV DCTL strung with 1113 kcmil SSAC conductor, 3. Loop the Helms – Gregg #1 and #2 230 kV lines into the E2 station, 4. Build a 230 kV line termination for each circuit at Midway and E2, and

5. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study.

Alt-6: Build a new PG&E and SCE Big Creek 230 kV Tie This alternative is similar to SCE’s Alternative 3 in the Conceptual SCE-PG&E Transmission Tie Study, except without the Midway – E2 500 kV DCTL. This alternative is to establish a new 230 kV system tie between SCE’s Big Creek system and PG&E’s Gregg – Helms 230 kV DCTL. This alternative includes the following facilities:

1. Build a new 230 kV switching station (E2), 2. Loop the Helms – Gregg #1 and #2 230 kV lines into E2 switching station 3. Loop four existing SCE’s 230 kV lines south of Big Creek (Big Creek 1-Rector 230-kV, Big Creek 3-Rector No. 1 and No. 2 230-kV and Big Creek 4- Springville 230-kV) into E2 230-kV switching station 4. Upgrade the four existing SCE 230 kV lines south of E2 to SCE’s load centers 5. Build a new 230 kV DCTL from E2 to S2. 6. A new double circuit 230-kV line from Magunden Substation to Rector Substation. 7. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study.

Alt-7: Build a Midway – McCall – E2 230 kV DCTL This alternative is to build a Midway – McCall – E2 230 kV DCTL. This alternative includes the following facilities:

1. Build a new 230 kV switching station (E2), 2. Loop the Helms – Gregg #1 and #2 230 kV lines into the E2 station, 3. Build a new 230 kV switching station (Pine Flat) in the Pine Flat Power House area, 4. Build a 230 kV DCTL from E2 to Pine Flat, 5. Build a new 230 kV termination for each new 230 kV line at E2 and Pine Flat, 6. Rebuild the Pine Flat – McCall section of the existing Haas - McCall 230 kV line and the Balch - McCall 230 kV line with 1113 kcmil SSAC conductors. 7. Upgrade terminations at the rebuilt Pine Flat – McCall 230 kV line sections to match the upgraded line capacity, 8. Build a Midway – McCall 230 kV DCTL strung with 1113 kcmil SSAC conductors on new right-of-way, 9. Build a new 230 kV termination for each new 230 kV line at Midway and McCall, 10. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study.

Alt-8: Build a Gates – Gregg 230 kV DCTL This alternative includes the following facilities:

1. Build a new Gates – Gregg 230 kV DCTL strung with 1113 kcmil SSAC conductors on a new right-of-way, 2. Build a 230 kV line termination for each circuit at Gates and Gregg. 3. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study.

Alt-9: Raisin City Switching Station This alternative includes the following upgrades:

1. Build a Raisin City 230kV switching station, 2. Re-build the Panoche – McCall 230 kV line, 3. Re-build the Panoche – Kearney 230 kV line, and 4. Re-build the Henrietta tap – McCall section of the Gates - McCall 230 kV line. 5. Upgrades line terminations of the rebuild 230 kV lines to match the upgraded line capacity 6. Install additional voltage supports in the Fresno area. The amount and location of the voltage support will be evaluated in a separate voltage stability study.

Alt-10: New Generation This alternative is to evaluate whether a future generation project in the Yosemite/Fresno area will meet the long-term goals. This alternative will study a combined cycle plant consisting of two combustion gas turbines generators (CTG) and one steam turbine generator (STG) connecting to the 230 kV bus at McCall Substation. The maximum net output to the CAISO Controlled Grid will be 600 MW with a commercial operation date of approximately 2011.

Reliability Assessments

1. Study Base Cases: This study will be based on the 2014 summer peak base case, 2014 off-peak base cases, and 2022 summer peak base case (a 15-year planning horizon). The 2014 summer peak base case will be used to evaluate load serving capability to the Fresno and Yosemite area by increasing Fresno and Yosemite area loads. The 2014 off-peak base cases will be used to test the robustness of the alternatives and to evaluate the available transmission capacity for serving off-peak loads and supporting helms pumping operation. The 2022 summer peak base case will be used to evaluate the import capability to access renewable resources in southern California and the future expansion to be integrated in northern California regional bulk transmission system for serving load growth in the San Francisco Bay area and Sacramento Valley area.

The 2014 summer peak and off-peak base cases will use the 2013 summer peak and off- peak base cases as the starting base cases that were developed in May 2007 for the Conceptual SCE-PG&E Transmission Tie Study. The 2013 summer peak base case was developed from the WECC 2015HS1B case that was approved by WECC on April 11, 2007. The 2013 Off-Peak case was developed from the WECC 2010LA1SA case that was approved by WECC on December 21, 2006. The power flow cases will be modified with the latest 1-in-10 year adverse weather load forecast for the Fresno and Yosemite areas, and will include CAISO-approved transmission projects (see Attachment 2), and new generation projects that are projected to be operational by 2014 (see Attachment 3). New generation Projects will be modeled in accordance with CAISO criteria for representing new generation projects.

The 2022 summer peak base case will be based on the 2017 summer peak base case (a07sum2017_gov.sav) developed for PG&E’s 2007 Electric Transmission Grid Expansion Plan. The base case will be modified with the latest 1-in-5 year load forecast for 2022. The 2022 base case will be used to test the robustness of the alternative’s ability to enable the system to meet CAISO Applicable Reliability Criteria 8 years after the operation date of the alternative. Because this case will simulate system conditions 15 years into the future, to support forecasted load growth and potential resource development, major conceptual transmission projects will need to be included in addition to the CAISO-approved projects, the majority of which are expected to be on line in the next 5 years. Such major conceptual transmission projects will be selected from the ones included in PG&E’s latest Transmission Expansion Plan in accordance with WECC and CAISO planning practices.

There are 36 additional power flow cases to be developed from these three base cases modeling the 12 potential alternatives as outlined above. Table 1 summarized the study assumptions and major path flow that will be modeled in the study base cases.

Table 1 Study Assumptions and Major Path Flow Study Base Cases 2014 Summer Peak 2014 off-peak 2022 Summer Peak 2015 Heavy Summer WECC 2010 Light Autumn 2015 Heavy Summer Starting WECC Base Case WECC Base Case WECC Base Case base case (2015HS1B) (2010LA1SA) (2015HS1B) 1 in 10 year load Yosemite and forecast for year Off-peak load 1 in 5 year load Fresno area load 2014 pattern forecast for year 2022 Fresno area generation Summer Peak Off-peak generation Summer Peak (excluding Helms) Generation Pattern pattern Generation Pattern 3 units pumping Helms units 0 unit generation1 (-900MW) 3 units generation Fresno area Hydro Summer peak Summer off-peak Summer peak average dispatch average hydro level average hydro level hydro level Include CAISO approved projects Future transmission Include CAISO Include CAISO (See Attachment 2) projects modeled in approved projects approved projects and major regional base cases (See Attachment 2) (See Attachment 2) conceptual projects 2 New generation Include projects Include projects Include projects projects modeled in w/PPA or UC w/PPA or UC w/PPA or UC base cases (See Attachment 3) (See Attachment 3) (See Attachment 3) Renewable contracts3 and one of PG&E’s Renewable renewable resources Resources modeled scenario for 33% RPS in base cases n/a n/a target Path 66 (COI) 4800 MW (n to s) 3650 MW (s to n) 4800 MW (n to s) Path 15 flow n/a 5400 MW (s to n) n/a Path 26 flow 4000 MW (n to s) <3000 MW (s to n) n/a 3 Helms units generation 2, 1 and 0 Helms Sensitive study (1212MW) unit pumping n/a

1 This is to evaluate load serving capability without Helms generation. 2 In addition to the approved projects shown in Attachment 2, the 2022 summer peak base case will also model the following two major regional conceptual transmission projects that are still under preliminary evaluation and have not received approval by either PG&E or the CAISO; Canada/Pacific Northwest – Northern California Transmission Project and Bay Area Bulk Transmission Project. These two conceptual projects were documented in PG&E’s 2007 Electric Grid Expansion Plan and are currently in the WECC Regional Planning Phase. Both conceptual transmission projects will have negligible impact on reliability analysis for the C3ET Project. Since they are non-approved projects, only preliminary project scopes will be considered in the study. The Canada/Pacific Northwest – Northern California Transmission Project will be represented as a renewable resource connected directly at Tesla. The origin of the renewable energy thus represented could be from the northern California, the Pacific Northwest, Canada, or northeast region of the WECC. 3 http://www.energy.ca.gov/portfolio/contracts_database.html updated January 14, 2008. See Attachment 4.

2. Renewable Resources In order to consider future transmission expansion possibilities, the 2022 summer peak base case will include a PG&E long term renewable resource procurement assumptions to meet a potential 33% RPS target. PG&E would procure about 16,000 GWH of additional renewable energy in 2022 to meet the potential 33% target that is above the renewable energy needed to meet a 20% target by 2010. This study assumes that northern California Municipalities would also procure renewable energy with the same renewable resources mix scenarios to meet a 20% target by 2022.

This study will adopt the 74-26% split of renewable resources between southern and northern California based on the renewable resources scenario used in the CEC sponsored Intermittency Analysis Project (IAP), which was vetted through a public stakeholder process. The total amount of additional renewable resources based on a 33% RPS assumption for PG&E and a 20% RPS assumption for northern California Municipal Utilities is about 8,400 MW in 2022. Of these 8,400 MW of renewable resources in the 2022 summer peak case, this study assumes that 6,200 MW (74%) would come from Southern California; 1,100 MW (13%) would come from Northern California, and 1,100 MW (13%) would come from outside of California (including the Pacific Northwest, British Columbia and northeast region of WECC). The potential amounts of renewable resources in the Western parts of the North American Continent have been discussed in numerous forums and are public information4.

In order to accommodate the projected levels of renewable resources and to balance loads and resources, several thermal power plants including the San Francisco Bay Area power plants, will need to be modeled off-line and the associated transmission projects required modeled on-line to meet NERC/WECC and CAISO Planning Standards. (See Attachment 5.) The generators to be modeled off-line will be selected first based on the Draft Study Plan on “Mitigation of Reliance on Old Thermal Generation Including Those Using Once-Through Cooling Systems” being developed in the CAISO Stakeholder Study Group5. Additional generators may potentially be modeled off-line as needed to balance load and resources.

3. 500 and 230 kV Contingencies See Attachment 6.

4. Sensitivity Studies: a. Drought Year Sensitivity Study This study will evaluate load serving capability to the Fresno and Yosemite area during a drought year. The drought year sensitivity study will be based on the 2014 summer

4 One such forum is the CEC hearings on the CEC Renewable Resource Development Report, which was subsequently approved by the CEC in November 2003 (http://www.energy.ca.gov/reports/2003-11-24_500-03-080F.PDF).

5 http://www.caiso.com/1c96/1c96dad822e50.pdf

partial-peak base case modeling drought year hydro generation in northern California. The drought year hydro generation pattern will be based on a historical drought year hydro generation pattern for the Fresno and Yosemite area. b. Sensitivity Studies to meet a scenario assuming a 20% RPS target in 2022 A 2022 summer peak base case modeling a scenario assuming a 20% RPS target will be developed for this sensitivity analysis. This scenario assumes that PG&E would procure about 3,000 GWH of additional renewable energy in 2022 above the renewable energy needed to meet a 20% target by 2010. c. Sensitivity Studies to meet a scenario assuming a 26% RPS target in 2022 A 2022 summer peak base case modeling a scenario assuming a 26% RPS target will be developed for this sensitivity analysis. This scenario assumes that PG&E would procure about 9,000 GWH of additional renewable energy in 2022 above the renewable energy needed to meet a 20% target by 2010.

5. Study Criteria Meet NERC, WECC and CAISO planning criteria. See Attachment 7. Under single generator outage (G-1), voltages at load buses should be above 95% and loading on all facilities should be under the normal capacity rating. Under single contingency (L-1/G- 1), voltages at load buses should be above 90% and loading on all facilities should be under emergency ratings without applying remedial action scheme. Under double contingency (L-2), voltages should be above 90% and loading at all facilities should under emergency ratings with applying existing remedial action scheme.

6. Study Scope This study will initially includes the steady state and post-transient power flow studies to evaluate the impact of the above potential alternatives during normal operating conditions, as well as, single and selected multiple outages (Category “B” and “C” contingencies). Based on the initial power flow studies results, stability studies will be conducted as necessary and economic analysis will be conducted for selected potential alternatives that meet reliability criteria according to reliability assessment.

7. Methodology for Reliability Analysis

a. Load Serving Capability to the Fresno and Yosemite Area

The load serving capability to the Fresno and Yosemite area is defined to be the total Fresno (Zone #314 and #344) and Yosemite (Zone #313 and #343) area loads that could be safely and reliably served under summer peak and summer partial-peak conditions. This study will evaluate the load serving capability under summer peak conditions with Helms generation at 1,212 MW, and under summer partial-peak conditions with Helms PSP off-line. For each alternative, the conforming loads in Fresno area (Zone #314) and Yosemite area (Zone #313) will be scaled up (or down) until the system reaches its limit. Contingencies cases will be run to make sure the post contingency loading are under the facility emergency rating.

b. Transmission Capacity for Supporting Helms Pumping Operation The transmission capacity for supporting Helms pumping operation is defined to be the capacity for serving Fresno and Yosemite area loads and supporting Helms pumping operation (one, two and three units pumping) under summer off-peak conditions. Based on a projected Fresno area load duration curve, the capacity for supporting Helms pumping operation could be translated to MWH of energy in generation mode.

c. Import Capability from southern California The import capability from southern California is defined to be the south-to-north transfer capability on Path 26 at Midway. This study will be based on two cases, the 2014 off- peak base case and the 2022 summer peak base case. The 2014 off-peak case will be used to evaluate the import capability at Midway under off-peak conditions. The 2022 summer peak base case will be used to evaluate the long term import capability at Midway to serve loads in northern California during on-peak conditions. The 2022 case will consider PG&E’s renewable resource scenarios for importing renewable resources from the Northwest/BC, northern California and from southern California. This study will evaluate, based on the 2022 case, the alternatives that have the potential for future expansion and could be integrated in the California regional bulk transmission system for serving load growth in the San Francisco Bay area, Sacramento Valley area and other areas.

Economic Assessments

The objective of the economic study is to quantify the economic benefit of a proposed project, which can be a buildup of transmission, generation or demand response to mitigate grid congestion and solve reliability issues. Among different studied alternatives, the alternative that offers the maximum net benefit (i.e. benefit minus cost) is generally considered as the most economic solution.

1. Methodology for Economic Analysis

Economic study further investigates alternatives that have been demonstrated to meet NERC, WECC and CAISO Planning Standards. Economic study is mainly based on production cost simulation that computes power flow and energy prices for all the 8760 hours in each study year. In the production cost simulation, thermal generators are committed and dispatched according to their costs subject to generation operation constraints (e.g., ramp rates, minimum up-time, minimum down-time, etc.) and transmission capacity constraints (e.g., line limits, flow gates limits, contingency constraints, nomograms, etc.). The power system is operated with minimum production cost as in a competitive and deregulated electricity market.

The study methodology is described as follows.

Study scope: The economic study simulates WECC-wide system operation for 2015 and 2020 respectively. For each study year, the study produces 8760 hours of power flow results and locational marginal prices (LMP).

Simulation tool used: The economic study uses Ventyx’s PROMOD IV, which is a commercial software employing algorithms of Security-Constrained Unit Commitment (SCUC) and Security- Constrained Economic Dispatch (SCED) to perform production simulation.

Assessment methodology: Based on the CAISO Transmission Economic Assessment Methodology (TEAM), the economic study summarizes consumer payment, producer profit and transmission congestion revenue in CAISO ratepayers’ perspective. By comparison of those dollars values between the pre-project and post-project, the project’s economic benefit is identified. Furthermore, the project’s total economic benefit (in present value) is derived. With the project’s benefit and cost, the net benefit is calculated. Finally, net benefits of different alternatives are compared against each other. The alternative that offers the largest net benefit is generally the most economic solution.

2. Study Base Cases for Economic Analysis The study base case stems from the WECC Production Cost Simulation Database for planning year 2015. Based on the WECC 2015 database, project base cases of 2015 and 2020 are developed with the modeling of approved new transmission and generation projects as well as other assumptions. See “Study Assumptions” for details.

In the economic study, the assumptions on generation, transmission and load are as follows:

Generation assumptions:

• In base case analysis, the study models new generation projects in the CAISO LGIP Queue if the projects are under construction or have Power Purchase Agreement (PPA). In sensitivity analysis, the impact of having 500 MW of combined cycle and additional 500 MW of solar generation in Fresno area. In the sensitivity analysis, the impact of 200 MW less new generation (Project Q#47 at Herndon – Kearney 230 kV line) will also be analyzed. See Attachment 3 for a list of new generation in the Greater Fresno Area in the CAISO LGIP Queue.

• Future renewable resources in California are represented to meet the state’s mandate of 26.5% penetration in 2015 and 33% in 2020 respectively.

• In base case analysis, the assumption for the natural gas price at Henry Hub is $7/MMBtu. In sensitivity analysis, the gas price will be varied by ±20% to assess the impact on the economic benefits.

• In sensitivity analysis, the impact of dispatching off old thermal generation plants (see Attachment 5) will be assessed.

• In sensitivity analysis, wet and dry hydro generation in the Fresno and Big Creek areas will be analyzed to assess the impact on the economic benefits.

Transmission assumptions:

Transmission projects that have received CAISO Board approval are modeled in the base cases. Those transmission projects include but not limited to:

1. Palo Verde Devers #2 Project 2. Tehachapi Transmission Project 3. Sunrise Powerlink Project 4. San Joaquin Cross Valley Loop Transmission Project

In addition to the transmission constraints modeled in the WECC base case, the following constraints are also modeled:

1. L-1 constraints for the Fresno area import lines. 2. L-1 constraints for the Big Creek area transmission lines.

3. Path 15 south-to-north OTC6 is modeled, which is a function of generation in the Midway area.

Load assumptions:

• In the base analysis, 1-in-2 system adverse weather load forecast will be used. The WECC base case will be modified, where necessary, to match the 2007 CEC load forecast. Furthermore, the Fresno and Big Creek area loads will be verified to match the area load forecast by PG&E and SCE respectively.

• In sensitivity analysis, 1-in-10 year adverse weather load forecast for the Fresno and Big Creek Areas will also be used to identify if load shedding takes place due to transmission constraints. In both base analysis and sensitivity analysis, any load shedding will be identified, where a penalty cost of $10,000/MWh is applied.

In summary, the economic study will compute the quantifiable benefit for each alternative. The project’s economic benefit will be calculated in dollar values in present worth. With that, the benefits of different alternatives can be compared against each other.

6 Operating Transfer Capacity

Preliminary Study Schedule

Responsible Preliminary Descriptions Parties Schedule 1 Announce 1st Stakeholder meeting on CAISO web site CAISO 12/19/2007 2 Prepare a draft study plan for review and comment PG&E, CAISO 12/20/2007 3 Post a draft study plan on CAISO web site CAISO 1/2/2008 1st and 2nd Stakeholder Meeting: Present draft 1/9/2008, 4 study plan PG&E, CAISO 2/6/2008 5 Stakeholders’ written comments on study plan All Stakeholders 1/23/2008 6 Publish 1st draft base cases for review and comments PG&E January, 2008 7 Finalize Study Plan PG&E, CAISO February, 2008 8 Stakeholder’s written comments on draft base cases All Stakeholders February, 2008 Finalize and publish the study base cases (peak and 9 off-peak) PG&E, CAISO February, 2008 PG&E 10 Complete steady-state and post-transient PF analysis March, 2008 11 Conduct economic analysis CAISO March, 2008 12 Complete Sensitivity studies PG&E April, 2008 3rd Stakeholder Meeting: Present preliminary 13 reliability study results PG&E, CAISO April, 2008 Stakeholder’s written comments on preliminary 14 reliability study results All Stakeholders April, 2008 15 Complete economic analysis CAISO April, 2008 4th Stakeholder Meeting: Present economic 16 analysis results PG&E, CAISO May, 2008 Stakeholder’s written comments on economic analysis 17 study results All Stakeholders May, 2008 Complete and issue draft planning report for review 18 and comment PG&E, CAISO July, 2008 5th Stakeholder Meeting (if needed): Review All 19 comments if any Stakeholders TBD 20 Incorporate comments and issue final study report PG&E, CAISO August, 2008

Attachment 1 One Line Diagram

Alt-1: Simplified Transmission System as expected by 2014 (Status Quo)

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon

230kV

E2 500/230 kV Sub

McCall Panoche 230kV 230kV Gates 500kV Path 15

Gates 230kV Diablo 500kV

Midway 500kV

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-2: Central California Clean Energy Transmission Project (C3ETP) Build a Midway–E2 500 kV DCTL (about 141 miles)

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon

230kV

E2 500/230 kV Sub

McCall Panoche 230kV 230kV Gates Path 15 500kV

Gates 230kV Diablo 500kV

Midway Midway - E2 500kV 500kV DCTL

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-2A: C3ETP Future Expansion Build a 500/230 kV Substation (S2) looping into one of the Midway–E2 500 kV Lines

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon

230kV

E2 500/230 kV Sub McCall 230kV

Panoche 230kV

Path 15

Gates 500kV S2 500/230 kV Sub (SCE)

Gates 230kV Diablo 500kV

Midway Midway - E2 500kV 500kV DCTL

Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-2B: C3ETP Future Expansion Same as Alt-2A, Except also building a Magunden 500 kV Substation (S3) looping into one of the Midway – E2 500 kV DCTL and building a new Magunden – Whirlwind 500 kV SCTL

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon

230kV

E2 500/230 kV Sub McCall 230kV Midway - E2 500kV DCTL Panoche 230kV

Gates Path 15 500kV S2 500/230 kV Sub (SCE)

Gates 230kV Diablo 500kV

Midway 500kV S3 500/230 kV Sub (SCE)

Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-2C: C3ETP Future Expansion Same as Alt-2A, Except also upgrade the Midway – Vincent #3 500 kV line

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon

230kV

E2 500/230 kV Sub McCall 230kV

Panoche 230kV

Path 15

Gates 500kV S2 500/230 kV Sub (SCE)

Gates 230kV Diablo 500kV

Midway Midway - E2 500kV 500kV DCTL

Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-3: Build a Midway – E2 500 kV SCTL (about 141 miles)

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon

230kV

E2 500/230 kV Sub

McCall Panoche 230kV 230kV Gates 500kV Path 15

S2 500/230 kV Sub (SCE)

Gates 230kV Diablo 500kV

Midway 500kV Midway - E2 500kV SCTL

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-4: Build a Whirlwind – E2 500 kV DCTL

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon 230kV

E2 500/230 kV Sub McCall 230kV Panoche 230kV

Gates Path 15 500kV S2 500/230 kV Sub (SCE)

Gates 230kV Diablo 500kV

Midway Whirlwind - E2 500kV 500kV DCTL

Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-5: Build a Midway – E2 230 kV DCTL

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon E2 230 kV Switching Sta

McCall Panoche 230kV 230kV Gates 500kV Path 15

Gates 230kV Diablo 500kV

Midway Midway - E2 500kV 230kV DCTL

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-6: Build a new PG&E and SCE Big Creek 230 kV Tie

Alt-7: Build a Midway – McCall – E2 230 kV DCTL

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos 230kV Herndon E2 230 kV Switching Sta

McCall 230kV

Panoche Pine Flat Balch PH #2 230kV PH Gates 500kV Path 15

Gates 230kV Midway – McCall - E2 Diablo 230kV DCTL 500kV

Midway 500kV

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-8: Build a Gates – Gregg 230 kV DCTL

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos Herndon 230kV

Gates – Gregg 230kV DCTL

McCall Panoche 230kV 230kV Gates 500kV Path 15

Gates 230kV Diablo 500kV

Midway 500kV

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-9: Build Raisin City Switching Station

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos Herndon 230kV

McCall 230kV Panoche 230kV Gates 500kV Raisin City 230kV Switching Station

Gates 230kV Path 15 Diablo 500kV

Midway 500kV

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Alt-10: New Generation

Tesla 500kV Tracy 500kV Metcalf 500kV

Moss Landing 500kV Helms Gregg 230kV

Los Banos 500kV

Los Banos Herndon 230kV

McCall Panoche 230kV 230kV New Generation Gates (600 MW) 500kV Path 15

Gates 230kV Diablo 500kV

Midway 500kV

Path 26 Whirlwind Sub-1 (SCE) (SCE)

Antelope (SCE)

Tehachapi Wind (SCE) Vincent 500kV (SCE)

Attachment 2 Transmission Facilities Included in Reliability Assessment Base Cases

All transmission expansion plan proposals that have received CAISO approval were modeled in the base cases based on their approved operational date. Below is a summary of planned projects with CAISO approval for the PG&E system:

Table A2-1 Transmission Projects Modeled in Reliability Assessments

Purpose CAISO Year Project Title And County Project Scope Approva Modeled in Benefit l Status Base Case Interconnect Airways Distribution Sub Interconnect 1 Fresno Distribution Yes 2007 Interconnection Customer Substation Bair-Belmont 115 kV Reconductor 115 kV 2 Reduce LCR San Mateo Yes 2007 Line Lines Meet Customer Colgate 230/60 kV Demand, and Nevada and Transformer 3 Yes 2007 Capacity Increase Improve Service Yuba Replacement Reliability Meet Customer Henrietta 230/70 kV Demand, and Install Second 230/70 4 Kings Yes 2007 Transformer Improve Service kV Transformer Reliability Meet Customer Fresno, Henrietta-Gregg 230 kV Demand and Reconductor 230 kV 5 Kings and Yes 2007 Reconductoring Reduce Lines Madera Generation Cost Meet Customer Hollister 115 kV Demand and Reconductor 115 kV 6 San Benito Yes 2007 Reconductoring Improve Service Lines Reliability Meet Customer Ignacio 115/60 kV Demand and Transformer 7 Marin Yes 2007 Transformer Improve Service Replacement Reliability Meet Customer Lakeville-Sonoma 115 Demand and Construct New 115 8 Sonoma Yes 2007 kV Line Improve Service kV Line Reliability Meet Customer Mesa 230/115 kV Demand and Transformer 9 Nipomo Yes 2007 Transformer Improve Service Replacements Reliability Mountain Quarries 60 Meet Customer Reconductor 60 kV 10 Placer Yes 2007 kV Tap Reconductoring Demand Line Meet Customer Tulucay 230/60 kV Demand and Install Second 230/60 11 Napa Yes 2007 Transformer Improve Service kV Transformer Reliability Meet Customer Bay Area Reactive: Demand, and Install Shunt 12 San Mateo Yes 2008 Ravenswood Improve Service Capacitors Reliability DCPP (Mesa) 230 kV Improve Service Install Shunt 13 Los Padres Yes 2008 Shunt Capacitors Reliability Capacitors Install Additional Del Monte 115/60 kV Improve Service 14 Monterey 115/60 kV Yes 2008 Transformer Reliability Transformer Improve Service 15 Gregg 230 kV Reactor Madera Install Shunt Reactors Yes 2008 Reliability

Purpose CAISO Year Project Title And County Project Scope Approva Modeled in Benefit l Status Base Case Meet Customer Herndon-Bullard 115 kV Demand and Fresno and Reconductor 115 kV 16 Yes 2008 Reconductoring Improve Service Madera Lines Reliability Humboldt - Harris 60 kV Meet Customer Reconductor 60 kV 17 Humboldt Yes 2008 Reconductoring Demand Line Humboldt Reactive Improve Service Install Voltage 18 Humboldt Yes 2008 Support Reliability Support Kasson-Lammers 115 Meet Customer Reconductor 115 kV 19 San Joaquin Yes 2008 kV Reconductoring Demand Lines Meet Customer Lakeville 230/60 kV Demand and Install Second 230/60 20 Transformer Capacity Sonoma Yes 2008 Improve Service kV Transformer Increase Reliability Interconnect (Delta) Lone Tree Interconnect 21 Contra Costa Distribution Yes 2008 Substation Customer Substation McCall 230/115 kV Improve Service Transformer 22 Transformer Fresno Yes 2008 Reliability Replacement Replacement Meet Customer Metcalf - El Patio 115 kV Demand, and Reconductor 115 kV 23 Santa Clara Yes 2008 Reconductoring Improve Service Lines Reliability Metcalf-Monta Vista 230 Reconductor 230 kV 24 kV Nos. 1 and 2 Reduce LCR Santa Clara Yes 2008 Lines Reconductoring Monterey Metcalf-Moss Landing Improve Service Reconductor 230 kV 25 and Santa Yes 2008 230 kV Reconductoring Reliability Lines Clara Meet Customer Monta Vista 115/60 kV Demand and Install 115/60 kV 26 Santa Clara Yes 2008 Transformer Improve Service Transformer Reliability Meet Customer Newark - Fremont 115 Demand and Reconductor 115 kV 27 Mission Yes 2008 kV Reconductoring Improve Service Lines Reliability Newark-Newark Reconductor Limiting 28 Reduce RMR Alameda Yes 2008 Distribution 230 kV Line Sections of Bus Palermo 230/115 kV Install a 230/115 kV 29 Reduce RMR Butte Yes 2008 Transformer Transformer Meet Customer Pease-Marysville 60 kV Demand and Yuba and Construct New 60 kV 30 Yes 2008 Line Improve Service Sutter Line Reliability Meet Customer Stagg 230/60 kV Demand and Transformer 31 San Joaquin Yes 2008 Transformers Improve Service Replacements Reliability Templeton – Atascadero Meet Customer San Luis Reconductor 70 kV 32 Yes 2008 70 kV Reconductoring Demand Obispo Line Vaca Dixon – Birds Access Reconductor 230 kV 33 Landing 230 kV Solano Yes* 2008 Resource Lines Reconductoring Reduce RMR Install Second Vaca Dixon 500/230 kV and Improve 34 Solano 500/230 kV Yes 2008 Transformer Service Transformer Reliability Reconductor and Improve Service 35 Weber #1 60 kV Line San Joaquin reconfigure the Weber Yes 2008 Reliability #1 60 kV Line

Purpose CAISO Year Project Title And County Project Scope Approva Modeled in Benefit l Status Base Case Meet Customer Atlantic - Pleasant Reconductor the Demand and 37 Grove 60 kV Placer Atlantic - Pleasant Yes* 2009 Improve Service Reconductoring Grove 60 kV lines Reliability Meet Customer Atlantic - Lincoln 60 kV Demand and Convert 60 kV 38 Placer Yes* 2009 to 115 kV Conversion Improve Service Facilities to 115 kV Reliability Meet Customer Construct a new 115 Lincoln - Rio Oso 115 Demand and kV line between 39 Placer Yes* 2009 kV Line Improve Service Lincoln and Rio Oso Reliability substations Install 70 kV Breaker Borden - Madera 70 kV Meet Customer 40 Madera and Construct Yes 2009 new line Demand Additional Line Gold Hill - Clarksville Meet Customer Reconductor 115 kV 41 115 kV Line El Dorado Yes 2009 Demand Lines Reconductoring Martin 115/60 kV Meet Customer San Transformer 42 Transformer Yes 2009 Demand Francisco Replacement Replacement Reduce RMR Martin-Hunters Point and Improve San Construct New 43 Yes 2009 115 kV Cable Service Francisco Underground Cable Reliability Meet Customer Palermo-Rio Oso 115 Demand and Yuba and Reconductor 115 kV 44 Yes* 2009 kV Line Reconductoring Improve Service Sutter Lines Reliability Meet Customer Placer 115 kV Demand and Reconductor 115 kV 45 Placer Yes 2009 Reinforcement Improve Service Lines or Equivalent Reliability Meet Customer Rio Oso 230/115 kV Transformer 46 Demand and Sutter Yes 2009 Transformer Upgrades Replacements Reduce LCR Meet Customer Replace transformers Soledad 115/60 kV Demand and at Soledad Substation 47 Monterey Yes 2009 Transformer Capacity Improve Service with 200 MVA Reliability Transformers West Point – Valley Meet Customer Reconductor 60 kV 48 Calaveras Yes 2009 Springs 60 kV Line Demand Line Bay Meadows 115 kV Meet Customer Reconductor 115 kV 49 San Mateo Yes 2010 Reconductoring Demand Lines Brighton 230/115 kV Meet Customer Transformer 50 Transformer Sacramento Yes 2010 Demand Replacement Replacement Reduce RMR Oakland Underground Construct New 51 and Reduce Alameda Yes 2010 Cable Underground Cable Congestion *Projects awaiting final board approval due to cost.

Attachment 3 Potential New Generation in the Greater Fresno Area

Table A3-1 Potential New Generation in the Greater Fresno Area in the CAISO LGIP Queue (As of 12/31/07) Queue Net Modeled Positio Point of Capacity Online in Base n Interconnection (MW) Date Type Status Cases 42 McCall Substation 303.0 2013 CT LGIA No Herndon – Kearney 47 230 kV line 200.0 2009 CT PPA Yes 52 Panoche Sub Station 401.0 2009 CT PPA Yes 54 Panoche Substation 119.9 2009 CT PPA Yes 61 70 kV Helm-Kerman 73.3 2006 ST Online Yes Le Grand-Chowchilla 75 115 kV 10.5 2008 B UC Yes PG&E Merced #1 70 76 kV circuit 10.5 2008 B UC Yes 128 McCall Substation 565.0 2010 CC FAS No 230 kV bus at Borden 196 Substation 508.0 2011 CC IFS No Borden Substation 230 247 kV Bus 57.0 2011 CC SIS No 272 Henrietta Substation 125.0 2010 S IFS No 272 Henrietta Substation 25.0 2012 CC IFS No Henrietta-Kingsburg 273 115 kV lines 75.9 2010 S SIS No Henrietta-Kingsburg 273 115 kV lines 24.0 2012 CC SIS No 282 115 kV Panoche Sub 29.0 2010 B IR No

Legend:

CT=Combustion Turbine, ST=Steam Turbine, CC=Combined Cycle, B=Biomass, S=Solar

IR=Interconnection Request, IFS=Interconnection Feasibility Study, SIS=System Impact Study, FAS=Facilities Study, LGIA=Large Generator Interconnection Agreement, UC=Under Construction, PPA=Power Purchase Agreement

Attachment 4 Renewable Resource List Modeled in 2022 Summer Peak Base Case)

Internal Trackin "Active" Minimu Maximu g Contrac Solicitat Technol Vintage/ m Size m Size Utility Number t ion ogy Type Facility Name Developer Name (MW) (MW) Location 2002 geother PG&E PGE001 inactive interim mal existing Geysers #13 Calpine 70 70 Geysers 2002 geother PG&E PGE002 inactive interim mal existing Geysers #20 Calpine 40 40 Geysers NDC Consulting 2002 Engineers, Big PG&E PGE003 active interim biomass existing Big Valley Valley Power Co. 7.5 7.5 Lassen/Round Mountain 2002 PG&E PGE004 active interim biomass existing Wheelabrator No. 4 Wheelabrator 3 3 Shasta/Cottonwood 2004 PG&E PGE005 active bilateral wind repower Diablo Winds FPL Energy 18 18 Altamont 2004 PG&E PGE006 inactive bilateral wind repower Buena Vista Energy Buena Vista 38 38 Altamont 2003 Firebaugh/Los Banos Switching PG&E PGE007 active bilateral biomass existing Madera Power Madera Power 24 24 Center Community 2003 Renewable Energy Reedley, Dinuba'Fresno PG&E PGE008 active bilateral biomass existing Services Yankee Energy 12 12 Operating Center 2003 Sierra Power PG&E PGE009 active bilateral biomass existing Sierra Power Corp. Corporation 7 7 Terra Bella (SCE) 2004 FPL Montezuma PG&E PGE010 active RPS wind new Wind FPL Energy 32.4 32.4 Solano 2004 PG&E PGE011 active RPS wind repower Buena Vista Energy Buena Vista 38 38 Altamont 2004 Pacific Renewable Pacific Renewable PG&E PGE012 active RPS wind new Energy Generation Energy Generation 82.5 82.5 Lompac/Midway 2004 Shiloh 1 Wind PG&E PGE013 active RPS wind new Project PPM 75 75 Solano 2005 Global Common's PG&E PGE014 active bilateral biomass re-start Chowchilla Global Ampersand 9 9 Panoche, Near Fresno 2005 Global Common's El PG&E PGE015 active bilateral biomass re-start Nido Global Ampersand 9 9 Panoche, Near Fresno 2004 geother Military Pass- PG&E PGE016 active RPS mal new Newberry Volcano Vulcan Power 120 120 30 miles southeast of Bend 2005 geother US Renewables PG&E PGE017 active RPS mal re-start Bottle Rock Group 10 55 NP15, Geysers 2005 PG&E PGE018 active RPS biogas new Liberty Liberty V Biofuels 5 10 NP15, Lost Hills 2005 HFI Bio Power PG&E PGE019 active RPS biomass new HFI Project LLC 20 40 NP15, La Pine Oregon 2005 geother Northwest PG&E PGE020 active RPS mal new Geothermal Davenport Power 30 120 Newberry Volcano, Oregon

Internal Trackin "Active" Minimu Maximu g Contrac Solicitat Technol Vintage/ m Size m Size Utility Number t ion ogy Type Facility Name Developer Name (MW) (MW) Location 2005 geother PG&E PGE021 active RPS mal new IAE Truckhaven IAE 49 49 Truckhaven, Imperial 2006 small PG&E PGE022 active bilateral hydro new Buckeye Tunnel Hill Hydro 0.4 0.4 El Dorado County 2006 small PG&E PGE023 active bilateral hydro new Tunnel Hill Tunnel Hill Hydro 0.6 0.6 El Dorado County 2006 PG&E PGE024 active bilateral biogas new Eden Vale Eden Vale Dairy 0.15 0.15 Kings County 2006 geother PG&E PGE025 active bilateral mal existing Geysers Calpine 200 200 Geysers 2007 PG&E PGE026 active bilateral biogas new BioEnergy LLC BioEnergy LLC 2 44.38 Fresno 2007 existing in Texas, new in Fresno PG&E PGE027 active bilateral biogas new Microgy Microgy 2 44.38 county 2006 PG&E PGE028 active bilateral biomass existing Pacific Lumber PALCO 6.8 6.8 Northern CA 2006 Sierra Pacific PG&E PGE029 active bilateral biomass new Lincoln Facility Industries 6.7 6.7 Lincoln 2006 geother Western GeoPower PG&E PGE030 active RPS mal new Western GeoPower Inc. 25.5 25.5 Sonoma County solar 2006 photovol PG&E PGE031 active RPS taic new Green Volts Green Volts Inc. 2 2 Byron, Calif. solar 2006 photovol PG&E PGE032 active RPS taic new CalRenew CalRENEW-1 LLC 5 5 Mendota, Calif. 2006 PG&E PGE033 active RPS wind new Klondike III PPM 85 85 Sherman County, Oregon 2005 solar Needles, Stedman or Arrowhead PG&E PGE034 active RPS thermal new SOLEL MSP-1 Solel 553.5 553.5 Junction 2007 PG&E PGE035 active bilateral wind new Shiloh II EnXco 150 150 Solano 2007 solar Carrizo Plain, San Luis Obispo PG&E PGE036 active bilateral thermal new Carrizo Energy LLC Ausra 177 177 County 2006 Finavera PG&E PGE037 active RPS ocean new Finavera Renewables 2 2 Humbolt County 2007 PG&E PGE038 active bilateral wind new White Creek PUD #1, Klickitat 50 50 Klickitat, WA

Attachment 5 List of Old Thermal Generation Plants (May be Modeled Off-line)

Attachment 6 List of Contingencies

NERC Category “A” No - Contingencies: • One major generator off-line in the Fresno and Yosemite area.

NERC Category “B” Contingencies (L-1 or T-1): • Tesla – Los Banos 500 kV line outage, • Tracy – Los Banos 500 kV line outage, • Los Banos – Gates #3 500 kV line outage, • Los Banos – Midway 500 kV line outage, • Gates – Midway 500 kV line outage, • Midway – E2 500 kV line outage, • Los Banos 500/230 kV transformer bank outage, • Gates 500/230 kV transformer bank outage, • Midway 500/230 kV transformer bank #11 outage, • E2 500/230 kV transformer bank outage.

NERC Category “B” Contingencies (L-1/G-1): • Helms #1 offline and Gates – Gregg 230 kV line outage, • Helms #1 offline and Gates – McCall 230 kV line outage, • Helms #1 offline and Panoche – Helm 230 kV line outage, • Helms #1 offline and Panoche – Kearney 230 kV line outage, • Helms #1 offline and Wilson – Storey – Gregg 230 kV line outage, • Helms #1 offline, and Borden – Gregg 230 kV line outage, • Kerckhoff 2 PH offline and Gates – Gregg 230 kV line outage, • Kerckhoff 2 PH offline and Gates – McCall 230 kV line outage, • Kerckhoff 2 PH offline and Panoche – Helm 230 kV line outage, • Kerckhoff 2 PH offline and Panoche – Kearney 230 kV line outage, • Kerckhoff 2 PH offline and Wilson – Storey – Gregg 230 kV line outage, • Kerckhoff 2 PH offline, and Borden – Gregg 230 kV line outage,

NERC Category “C” Contingencies (L-2):

• Loss of the Los Bano – Midway 500 kV line and the Gates – Midway 500 kV line, • Loss of the Los Banos – Midway 500 kV line and the Los Banos – Gates #3 500 kV line, • Loss of the Tesla – Los Banos 500 kV line and the Tracy – Los Banos 500 kV lines, • Loss of the Midway – Vincent #1 and #2 500 kV lines, • Loss of the Gates – Gregg 230 kV line and the Gates – McCall 230 kV line, • Loss of the Panoche – Helm 230 kV line and the Panoche – Kearney 230 kV line, • Loss of the Bellota - Wilson 230 kV line and the Melones – Wilson 230 kV line, • Loss of the Borden – Gregg 230 kV line and the Wilson – Storey - Gregg 230 kV line,

Attachment 7 Reliability Criteria

Cal-ISO Grid Planning Criteria WECC Reliability Criteria (excerpt) NERC Planning Standards (excerpt)

Attachment III - Cal-ISO Grid Planning Criteria

I. Background

The purpose of this document is to specify the Planning Criteria that will be used in the planning of ISO Grid transmission facilities.

The ISO Tariff specifies:

“After the ISO Operations Date, the ISO, in consultation with Participating TOs and any affected UDCs, will work to develop a consistent set of reliability criteria for the ISO Controlled Grid which the TOs will use in their transmission planning and expansion studies or decisions.”7

The ISO Tariff specifies in several places that the facilities that are to be added to the ISO Grid are to meet the Applicable Reliability Criteria, which is defined as follows:

“The reliability standards established by NERC, WECC, and Local Reliability Criteria as amended from time to time, including any requirements of the NRC.”8

These ISO Grid Planning Criteria will fill the role of the “local reliability criteria” in the above definition. To facilitate the development of these criteria, the ISO formed the ISO Grid Planning Criteria Subcommittee (PCS), which includes representation from all interested market participants. In recognition of the need to closely coordinate the development of the ISO Grid with neighboring electric systems both inside and outside of California, the approach taken by the PCS is to utilize regional (WECC) or continental (NERC) standards to the maximum extent possible. These ISO Grid Planning Criteria build off of, rather than duplicate, criteria that were developed by WECC and NERC. The PCS has determined that the ISO Grid Planning Criteria should:

• Address specifics not covered in the NERC Standards and WECC Criteria. • Provide interpretations of the NERC Standards and WECC Criteria specific to the ISO Grid. • Identify whether specific criteria should be adopted that are more stringent than the NERC Standards or WECC Criteria.

7 ISO Tariff, April 7, 1998, Section 3.2.1.2, Page 129. 8 ISO Tariff, April 7, 1998, Appendix A, Page 297.

The following paragraphs describe the general philosophy behind the ISO Planning Criteria and how the NERC Standards and WECC Criteria will affect the planning of the ISO grid.

II. ISO Grid Planning Criteria Principles

The primary principle guiding the development of the ISO Grid Planning Criteria is to develop a consistent reliability criteria for the ISO grid that will maintain or improve the level of transmission system reliability that existed with the pre-ISO planning criteria.

III. ISO Grid Planning Standards (excerpt)

I. Introduction The purpose of this document is to specify the Planning Standards that will be used in the planning of ISO Grid transmission facilities. The primary principle guiding the development of the ISO Grid Planning Standards is to develop a consistent reliability standards for the ISO grid that will maintain or improve the level of transmission system reliability that existed with the pre-ISO planning standards.

The ISO Tariff specifies:

The ISO Tariff specifies in several places that the facilities that are to be added to the ISO Grid are to meet the Applicable Reliability Standard, which is defined as follows:

“The reliability standards established by NERC, WSCC, and Local Reliability Criteria as amended from time to time, including any requirements of the NRC.”2

These ISO Grid Planning Standards fill the role of the “consistent set of reliability criteria” in the above tariff language. To facilitate the development of these Standards, the ISO formed the ISO Grid Planning Standards Committee (PSC), which includes representation from all interested market participants. One of the primary roles of the PSC is to periodically review the ISO Grid Planning Standards and recommend changes as necessary. In recognition of the need to closely coordinate the development of the ISO Grid with neighboring electric systems both inside and outside of California, the approach taken by the PSC is to utilize regional (WSCC) and continental (NERC) standards to the maximum extent possible. These ISO Grid Planning Standards build off of, rather than duplicate, Standards that were developed by WSCC and NERC. The PSC has determined that the ISO Grid Planning Standards should:

• Address specifics not covered in the NERC/WSCC Planning Standards. • Provide interpretations of the NERC/WSCC Planning Standards specific to the ISO Grid. • Identify whether specific criteria should be adopted that are more stringent than the NERC/WSCC Planning Standards.

The following Section details the ISO Grid Planning Standards. Also attached are interpretations of the terms used by NERC and background information behind the development of these standards.

The ISO Grid Planning Standards include the following:

1. NERC/WSCC Planning Standards -The standards specified in the NERC/WSCC Planning Standards unless WSCC or NERC formally grants an exemption or deference to the ISO. 2. Specific Nuclear Unit Standards -The criteria pertaining to the Diablo Canyon and San Onofre Nuclear Power Plants, as specified in Appendix E of the Transmission Control Agreement. 3. 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 Planning Standards for Category B contingencies. 4. New Transmission versus Involuntary Load Interruption Standard A. Involuntary load interruptions are not an acceptable consequence in planning for ISO Planning Standard Category B disturbances (either single contingencies or the combined contingency of a single generator and a single transmission line), unless the ISO Board decides that the capital project alternative is clearly not cost effective (after considering all the costs and benefits). In any case, planned load interruptions for Category B disturbances are to be limited to radial and local network customers as specified in the NERC Planning Standards. B. Involuntary load interruptions are an acceptable consequence in planning for ISO Planning Standard Category C and D disturbances (multiple contingencies with the exception of the combined outage of a single generator and a single transmission line),unless the ISO Board decides that the capital project alternative is clearly cost effective (after considering all the costs and benefits). C. In cases where the application of Standards 4A and 4B would result in the elimination of a project or relaxation of standards that would have been built under past planning practices, these cases will be presented to the ISO Board for a determination as to whether or not the projects should be constructed.

5. San Francisco Greater Bay Area Generation Outage Standard - Before conducting Grid Planning studies for the San Francisco Greater Bay Area, the following three units should be removed from service in the base case:

• One 50 MW CT in the Greater Bay Area but not on the San Francisco Peninsula.

• The largest single unit on the San Francisco Peninsula. • One 50 MW CT on the San Francisco Peninsula.

The case with the above three units out of service should be treated as the “system normal” or starting base case (NERC Category A) when planning the system. Traditional contingency analysis, based on the standards specified in the NERC, WSCC (including voltage stability), and ISO standards (such as single line outage, single generator outage etc), would be conducted on top of this base condition. The one exception is that when screening for the most critical single generation outage, only units that are not on the San Francisco peninsula should be considered. Similarly, when examining multiple unit outages, at least one of the units considered should not be on the San Francisco Peninsula.

This standard is intended to apply to system planning studies and not system operating studies. In addition, this standard has not been designed to be used to determine Reliability Must-Run generation requirements. The RMR standards are intentionally developed separately from the Planning Standards. It is recognized that it may require several years to add the facilities to the system that are necessary to allow the system to meet this standard. The amount of time required will depend on the specific facility additions this standard generates.

IV. WECC Transmission System Planning Criteria

The WECC Criteria for Transmission System Planning was originally developed to insure that disturbances in one system do not spread to other systems and produce widespread transmission system outages. Recently the WECC Criteria have been amended to provide specific requirements for internal system design. The WECC criteria are currently primarily deterministic criteria but WECC is working towards transitioning to probabilistic criteria. The ISO has also expressed strong interest in developing probabilistic criteria. The ISO and its members should be proactive in guiding NERC and WECC in this direction. Until probabilistic criteria are adopted by WECC, the current criteria will apply. In areas where the PCS believes that it would be uneconomic to comply with specific standards, the ISO can apply for deference with NERC and WECC.

V. NERC Planning Standards

In September of 1997, the NERC Board of Trustees approved the NERC Planning Standards. The approval of these standards marked a significant change for NERC and significantly affects the development of the ISO Grid Planning Criteria. Prior to the Planning Standards, NERC only provided “Planning Principles and Guides” which were very general. In contrast, the NERC Planning Standards provide specific planning requirements. In addition the NERC Planning Standards apply uniformly across bulk electric systems and do not distinguish between internal and external systems. The NERC Planning Standards appear to provide the majority of what is needed for an ISO Grid Planning Criteria. However, there is still a major question concerning the cost impact of implementing a stringent interpretation of the NERC Planning Standards. In addition, in past PCS meetings, a variety of entities expressed concern over a lack of clarity on some

points in the NERC Planning Standards. The PCS decided that clarifications to the NERC Standards should be developed and that it would be preferable for the PCS to develop the interpretations rather than request that NERC provide clarifications. The adoption of specific interpretations may directly impact the costs associated with compliance with the NERC Planning Standards. If NERC or WECC provides clarifications that are different than the ones adopted by the PCS, then those clarifications will apply unless the ISO has been granted deference.

V. Interpretations of NERC Planning Standard Terms

Listed below are several of the terms that are used in the NERC Planning Standards which members of the PCS have determined require clarification. Also provided below are ISO interpretations of these terms:

Bulk Electric System: The ISO Bulk Electric System refers to all of the facilities placed under ISO control.

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 PTOs and the ISO subject to appropriate coordination and review with the relevant state, local, and federal regulatory authorities and WECC. The PTOs develop annual transmission plans, which the ISO reviews. Both the ISO and PTOs have the ability to identify transmission upgrades needed for reliability.

Entity Required to Develop load models: The TOs, in coordination with the UDCs and others, develop load models.

Projected Customer Demands: The load level modeled in the studies can significantly impact the facility additions that the studies identify as necessary. The PCS decided that 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 higher 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 in the ISO Grid Coordinated Planning Process and corresponding operating procedures are in place when required. The PCS is developing guidelines for the use of load dropping to meet planning criteria.

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.

Appropriate Level of Reactive Reserves: As determined by the WECC “Voltage Stability Criteria, Undervoltage Load Shedding Strategy, and Reactive Power Reserve Monitoring Methodology” except where a specific area of the system warrants more stringent criteria.

VI. ISO Grid Planning Criteria

The ISO Grid Planning Criteria consists of the following:

1) The criteria specified in the WECC Criteria for Transmission System Planning unless WECC formally grants an exemption or deference to the ISO. 2) The standards specified in the NERC Planning Standards, and the interpretations discussed in Section V of this document, unless NERC formally grants an exemption or deference to WECC or the ISO. 3) The criteria pertaining to the Diablo Canyon and San Onofre Nuclear Power Plants, as specified in Appendix E of the Transmission Control Agreement. 4) A single transmission circuit outage with one generator already out of service and the system adjusted shall meet the performance requirements of the NERC Planning Standards for Category B contingencies.

In addition to these criteria, the PCS will be developing planning guidelines to provide guidance on a variety of issues such as the use of load dropping to meet applicable WECC and/or NERC criteria. These Planning Guidelines may evolve to be specific enough to be incorporated into this document as planning criteria.

JCM/GrdPlng

Attachment IV - WECC Reliablity Criteria (excerpt)

WECC Disturbance-Performance Table of Allowable Effect on Other Systems (1)

Performance Disturbance (2) Transient Voltage Dip Minimum Transient Post Loading Damping Level Initiated By: Criteria Frequency Transient Within No Fault Voltage Emergency 3 Ø Fault - Normal Clearing (4) (5) (6) (4) (5) Deviation Ratings SLG Fault - Delayed Clearing DC Disturbance (3) (4) (5) (6) (7)

A Generator Max V Dip - 25% 59.6 Hz 5% Yes >0 One Circuit One Transformer Max Duration of V Dip Duration of Frequency DC Monopole (8) Exceeding 20% - 20 cycles Below 59.6 Hz - 6 cycles

B Bus Section Max V Dip - 30% 59.4 Hz 5% Yes >0

Max Duration of V Dip Duration of Frequency Exceeding 20% - 20 cycles Below 59.4 Hz - 6 cycles

C Two Generators Max V Dip - 30% 59.0 Hz 10% Yes >0 Two Circuits DC Bipole (8) Max Duration of V Dip Duration of Frequency Exceeding 20% - 40 cycles Below 59.0 Hz - 6 cycles

D Three or More circuits on ROW Max V Dip - 30% 58.1 Hz 10% No >0 Entire Substation Entire Plant Including Switchyard Max Duration of V Dip Duration of Frequency Exceeding 20% - 60 cycles Below 58.1 Hz - 6 cycles

(1) This table applies equally to the system with all elements in service and the system with one element removed and the system adjusted. (2) The examples of disturbances in this table provide a basis for estimating a performance level to which a disturbance not listed in this table would apply. (3) Includes Disturbances which can initiate a permanent single or double pole DC outage. (4) Maximum transient voltage dips and duration, minimum transient frequency and duration, and post transient voltage deviations in excess of the values in this table can be considered acceptable if they are acceptable to the affected system or fall within the affected system's internal design criteria. The transient frequency must remain below the indicated frequency for more than six cycles to be considered a violation. (5) Transient voltage and frequency performance parameters are measured at load buses (including generating unit auxiliary loads), however, the transient voltage dip should not exceed 30% for any bus. Allowable post transient voltage deviations apply to all buses. (6) Refer to Figure 1. (7) If it can be demonstrated that post transient voltage deviations that are less than these will result in voltage instability, the system in which the disturbance originated and the affected system(s) should cooperate in mutually resolving the problem. Simulation of post transient conditions will limit actions to automatic devices only and no manual action is to be assumed. (8) Refer to section 8.0 - Application to DC Lines, paragraph 8.2.

Attachment IV - NERC Planning Standards (excerpt)

Transmission System Standards - Normal and Contingency Conditions

Contingencies System Limits or Impacts Loss of Components Demand or Category Thermal Voltage System Cascading c Initiating Event(s) and Contingency Component(s) Out of Curtailed Limits Limits Stable Outages Service Firm Transfers A – No All Facilities in Service None Normal Normal Yes No No Contingencies Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with a Normal Clearing: Applicable Rating b 1. Generator Single (A/R) A/R Yes No No b B – Event resulting 2. Transmission Circuit Single A/R A/R Yes No No b in the loss of a single 3. Transformer Single A/R A/R Yes No No component. b Loss of a Component without a Fault. Single A/R A/R Yes No No Single Pole Block, Normal Clearing: 4. Single Pole (dc) Line Single A/R A/R Yes Nob No SLG Fault, with Normal Clearing: 1. Bus Section Multiple A/R A/R Yes Plannedd No 2. Breaker (failure or internal fault) Multiple A/R A/R Yes Plannedd No SLG or 3Ø Fault, with Normal Clearing, Manual System Adjustments, followed by another SLG or 3Ø Fault, with Normal Clearing: 3. Category B (B1, B2, B3, or B4) contingency, Multiple A/R A/R Yes Plannedd No C – Event(s) manual system adjustments, followed by another resulting in the loss Category B (B1, B2, B3, or B4) contingency of two or more Bipolar Block, with Normal Clearing: (multiple) 4. Bipolar (dc) Line Multiple A/R A/R Yes Plannedd No components. Fault (non 3Ø), with Normal Clearing: 5. Double Circuit Towerline Multiple A/R A/R Yes Plannedd No SLG Fault, with Delayed Clearing: 6. Generator Multiple A/R A/R Yes Plannedd No 7. Transformer Multiple A/R A/R Yes Plannedd No 8. Transmission Circuit Multiple A/R A/R Yes Plannedd No 9. Bus Section Multiple A/R A/R Yes Plannedd No

D e – Extreme event 3Ø Fault, with Delayed Clearing (stuck breaker or Evaluate for risks and consequences. resulting in two or protection system failure): more (multiple) 1. Generator • May involve substantial loss of customer demand and generation in a widespread area or areas. components removed 2. Transmission Circuit • Portions or all of the interconnected systems may or may not achieve a new, stable operating point. or cascading out of 3. Transformer • Evaluation of these events may require joint studies with neighboring systems. service 4. Bus Section • Document measures or procedures to mitigate the extent and effects of such events. • Mitigation or elimination of the risks and consequences of these events shall be at the discretion of the 3Ø Fault, with Normal Clearing: entities responsible for the reliability of the interconnected transmission systems. 5. Breaker (failure or internal fault)

Other: 6. Loss of towerline with three or more circuits 7. All transmission lines on a common right-of way 8. Loss of a substation (one voltage level plus transformers) 9. Loss of a switching station (one voltage level plus transformers) 10. Loss of a all generating units at a station 11. Loss of a large load or major load center 12. Failure of a fully redundant special protection system (or remedial action scheme) to operate when required 13. Operation, partial operation, or misoperation of a fully redundant special protection system (or remedial action scheme) for an event or condition for which it was not intended to operate 14. Impact of severe power swings or oscillations from disturbances in another Regional Council.

(a) Applicable rating (A/R) refers to the applicable normal and emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or facility owner. (b) Planned or controlled interruption of generators or electric supply to radial customers or some local network customers, connected to or supplied by the faulted component or by the affected area, may occur in certain areas without impacting the overall security of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted firm (non-recallable reserved) electric power transfers. (c) Cascading is the uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread service interruption which cannot be restrained from sequentially spreading beyond an area predetermined by appropriate studies. (d) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, or the curtailment of contracted firm (non-recallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems. (e) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated.