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Application No.: A.10-04-002 Exhibit No.: SCE-3 Witnesses:

(U 338-E)

Energy Resource Recovery Account (ERRA) Reasonableness of Operations, 2009

SCE-1 and SCE-2 Appendices PUBLIC VERSION

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaApril 1, 2010

-i-

SCE-1 and SCE-2 APPENDICES PUBLIC VERSION

Table of Contents

Appendix V-A PEAKER OUTAGES – 2009

Appendix VI-A FONTANA AND CHINO SITE OUTAGES

Appendix VIII-A AES HUNGINGTON BEACH AMENDMENT NO. 1

Appendix VIII-B BE CA LLC for Alamitos Unit 2 Amendment No. 2 4/1/2007-12/31/2010

BE CA LLC for Alamitos Unit 3 Amendment No. 2 5/1/2006-12/31/2010

BE CA LLC for Alamitos Unit 4 Amendment No. 2 5/1/2006-12/31/2010

BE CA LLC for Redondo Beach 5 Amendment No. 2 5/1/2006-12/31/2010

BE CA LLC for Redondo Beach 7 Amendment No. 2 1/1/2007-13/31/2010

Appendix VIII-C Colton & CDWR MRTU Agreement

Appendix VIII-D High Desert MRTU Agreement

Appendix VIII-E Mountainview Power Company LLC Termination Agreement

Appendix VIII-F Reliant Energy Ellwood, Inc. 1st Amendment Reliant Energy Etiwanda, Inc. 1st Amendment Reliant Energy Mandalay, Inc. 1st Amendment Reliant Energy, Inc Name Change Notice

Appendix VIII-G REDACTED

Appendix VIII-H REDACTED

Appendix VIII-I REDACTED

Appendix VIII-J REDACTED

Appendix VIII-K REDACTED

Appendix VIII-L REDACTED

Appendix IX-A PURPA – List of Projects

Appendix IX-B PURPA – Payment Details

Appendix X-A RPS – List of Projects

Appendix X-B RPS – Payment Details

Appendix XV-A Detailed Overview Of Original And MRTU Market Structures

Appendix XVI-A Monthly Mohave Status Report

Appendix V-A

Peaker Outage Type Start

Duration (Hours) Outage Cause

BARRE Forced 1/12/2009 9:47 4.12

BAD TRIP MONITOR RELAY ON 252F2 BREAKER. REMOVED AND REPLACED BAD TRIP MONITOR RELAY.

MIRA LOMA Forced 1/13/2009 14:52 1.38

LOCATE AND CHECK BLACK START GENERATOR CURRENT TRANSFORMERS

BARRE Forced 1/20/2009 10:30 5.92

GROUND ON 24 VDC CONTROL BUS. GROUND CLEARED AND RELAYS RESET

MIRA LOMA Forced 2/10/2009 14:42 0.83 PERFORMED BLACK START TESTING

GRAPELAND Forced 2/10/2009 16:56 1.37 PERFORMED BLACK START TESTING

CENTER Forced 2/11/2009 11:02 0.47 PERFORMING BLACK START TESTING

CENTER Forced 2/11/2009 14:02 1.05 PERFORMED BLACK START TESTING

GRAPELAND Forced 2/12/2009 8:45 0.85 PERFORMED BLACK START TESTING

MIRA LOMA Scheduled 3/2/2009 0:00 228.65 SPRING MAINTENANCE OUTAGE

MIRA LOMA Scheduled 3/11/2009 15:42 0.17 SPRING MAINTENANCE OUTAGE

GRAPELAND Scheduled 3/16/2009 0:00 230.40 SPRING MAINTENANCE OUTAGE

CENTER Scheduled 4/6/2009 0:02 253.60 SPRING MAINTENANCE OUTAGE

CENTER Scheduled 4/16/2009 15:30 1.08 SPRING MAINTENANCE OUTAGE

BARRE Scheduled 4/20/2009 0:00 264.00 SPRING MAINTENANCE OUTAGE



GRAPELAND Forced 5/14/2009 12:38 3.87

FIBER OPTIC COMMUNICATION LINE SEVERED OFF SITE DUE TO CONSTRUCTION.


MICRONET CPU CARD CAUSED LOSS OF CONTROLS ON HMI


MICRONET CPU CARD MADE INTERMITTENT CONTACT WITH PINS AND CAUSED LOSS OF CONTROLS

MIRA LOMA Forced 5/19/2009 13:57 1.82 NERC/CIP SECURITY COMPLIANCE UPGRADE

CENTER Forced 6/3/2009 8:30 1.50 HMI/TCP INOPERABLE DUE TO FAILED CPU PROCESSOR

CENTER Forced 6/30/2009 8:02 1.47 TURBINE GAS VENT VALVE



6208 STUCK OPEN

MIRA LOMA Forced 8/24/2009 13:51 0.72

FUEL GAS COMPRESSOR TRIPPED WITH UNIT AT FULL LOAD CAUSING UNIT TRIP

BARRE Forced 9/17/2009 11:30 35.73 UNABLE TO CLOSE CB 252F1

MIRA LOMA Forced 9/19/2009 6:15 2.85 SCS ETHERNET CARD FAILED ON COMMUNICATION

BARRE Scheduled 10/5/2009 0:00 230.25 FALL MAINTENANCE OUTAGE

CENTER Forced 10/12/2009 9:04 2.77

LOST UPS SYSTEM AND CONTROLS. UNABLE TO CONTROL REMOTELY FROM CONTROL ROOM.


LOST UPS SYSTEM AND LOST CONTROLS. UNABLE TO CONTROL SITES REMOTELY FROM CONTROL ROOM

MIRA LOMA Forced 10/12/2009 9:04 2.77

LOST UPS SYSTEM AND CONTROLS. UNABLE TO CONTROL REMOTELY VIA CONTROL ROOM

BARRE Scheduled 10/14/2009 15:13 1.90 FALL MAINTENANCE OUTAGE BARRE Scheduled 10/14/2009 18:09 0.20 FALL MAINTENANCE OUTAGE

CENTER Forced 10/16/2009 11:22 6.27

FUEL GAS VENT VALVE FAILED OPEN. SOV-6208 REPLACED

CENTER Scheduled 10/19/2009 0:00 204.98 FALL MAINTENANCE OUTAGE CENTER Scheduled 10/27/2009 14:04 0.93 FALL MAINTENANCE OUTAGE

CENTER Forced 10/29/2009 11:51 1.45

TESTING FOR GAS LEAKS INSIDE TURBINE AND GENERATOR ENCLOSURE DUE TO INTERMITTENT READINGS

CENTER Forced 10/29/2009 18:46 4.22

BAD LEL SENSOR (GAS DETECTOR) TRIPPED CTG OFFLINE. REPLACED SENSOR

GRAPELAND Scheduled 11/2/2009 0:00 201.90 FALL MAINTENANCE OUTAGE

BARRE Scheduled 11/12/2009 8:00 1.02

PERFORM BLACK START TESTING PER CAISO REQUIREMENTS

BARRE Scheduled 11/12/2009 9:56 0.95

PERFORM BLACK START TESTING PER CAISO REQUIREMENTS

CENTER Forced 11/14/2009 17:29 21.08

GAS DETECTOR MONITOR FAILED. BAD SIGNAL DUE TO GROUNDED AND DAMAGED WIRING.

MIRA LOMA Scheduled 11/16/2009 0:00 205.03 FALL MAINTENANCE OUTAGE MIRA LOMA Scheduled 11/24/2009 13:03 1.50 FALL MAINTENANCE OUTAGE

BARRE Scheduled 12/2/2009 7:00 10.20

INSTALL NEW GAS CHROMATOGRAPHY EQUIPMENT.



CENTER Scheduled 12/3/2009 7:00 10.22

INSTALL NEW GAS CHROMATOGRAPHY EQUIPMENT

GRAPELAND Scheduled 12/4/2009 6:57 11.10

INSTALL NEW GAS CHROMATOGRAPHY EQUIPMENT

CENTER Forced 12/7/2009 8:56 0.67

FUEL GAS COMPRESSOR TRIPPED CAUSING A SPIKE IN FUEL PRESSURE RESULTING IN A CTG TRIP.

MIRA LOMA Scheduled 12/8/2009 7:00 3.65 BLACK START TESTING MIRA LOMA Scheduled 12/8/2009 11:48 3.08 BLACK START TESTING

GRAPELAND Scheduled 12/17/2009 7:00 7.10 480V TIE IN POWER TO NEW BUILDING

CENTER Scheduled 12/28/2009 16:50 1.03

TIE IN NEW POWER TO GAS CHROMATOGRAPHY EQUIPMENT

Appendix VI-A

Action Required CommentsOOS EST RTS

SPVP001 Fontana Business Operation Date 11/26/08

1 FO X 12/2/08 2:00 12/11/08 16:15 230:15 HrsReplace Breakers Secure

SwitchgearTheft of Breakers from Main Switchboard

2 DCE 12/19/08 10:00 12/20/08 14:30 28:30 Hrs Reset ATT ECN Circuit Communication Equipment Failure3 DCE 12/31/08 16:50 1/1/09 12:15 19:25 Hrs Reset ATT ECN Circuit Communication Equipment Failure4 PO X 1/8/09 8:00 1/8/09 11:15 3:15 Hrs Inverter Restart Inverter Offline � Required Restart5 PO X 1/14/09 7:30 1/14/09 12:30 5:00 Hrs Inverter Restart Inverter Offline � Required Restart6 DCE 1/15/09 8:00 1/15/09 11:15 3:15 Hrs Software Upgrade Inverter Vendor Installed Software Upgrade7 DCE 1/20/09 11:00 1/20/09 16:45 5:45 Hrs Vendor Service Call Communications circuit board replaced8 DCE 1/22/09 11:45 1/22/09 13:00 1:15 Hrs Vendor Service Call Vendor calibration of Inverters9 DCE 1/23/09 7:15 1/23/09 17:00 9:45 Hrs Vendor Software Patch Communication Equipment Failure10 DCE 1/24/09 7:15 1/24/09 17:00 9:45 Hrs Vendor Software Patch Communication Equipment Failure11 DCE 1/25/09 7:15 1/25/09 17:00 9:45 Hrs Vendor Software Patch Communication Equipment Failure12 FO 1/26/09 7:15 1/26/09 17:00 9:45 Hrs Vendor Software Patch Communication Equipment Failure13 DCE 2/7/09 2:30 2/7/09 7:17 4:47 Hrs Reset ATT ECN Circuit Communication Equipment Failure

14 SO X3/3/2009 6:45 3/3/2009 7:08

0:23 HrsNone Unit off�line to perform corrective maintenance to expansion joints on roof.

15 SO X3/6/09 16:45 3/6/09 17:15

0:30 HrsNone Unit off�line to perform corrective maintenance to expansion joints on roof.

16 PO X 3/7/2009 10:30 3/7/2009 17:45 7:15 Hrs Vendor Service Call Inverter Offline � Required repairs and restart17 PO X 3/8/2009 6:45 3/8/2009 17:45 11:00 Hrs Vendor Service Call Inverter Offline � Required repairs and restart

18 PO X 3/9/2009 6:00 3/9/2009 10:30 4:30 Hrs Vendor Service CallFailed feedback signal to the control board due to dirty contact. VendorCleaned Connection

19 PO X 3/14/2009 8:15 3/14/2009 9:52 1:37 Hrs Vendor Service CallFailed feedback signal to the control board due to dirty contact. ControlBoard replaced.

20 SO X 9/23/2009 11:28 9/23/2009 12:40 1:12 Hrs Electrical Interconnection Test Operational impact test conducted

21 PO X 11/22/2009 6:50 11/23/2009 8:20 25:30 Hrs Vendor Service Call Inverter Offline � Fuse replaced.Outage Total

21Fontana Availability Factor 99.9% Updated:3/24/2010

Availability Factor Calculation290:27 Hrs

960099.9%

* ON : on�line, dispatched per schedule unless noted; OFF : off�line, dispatched per schedule unless noted; FO : forced outage; SO : scheduled outage; TBD : To Be Determined; RO: Reporting Outage; PO : Partial Outage; DCE : Data Communications Error;

Outage DatesPlant/Unit Outage Number Unit Status*

Lost Production

Total Downtime

Plant/UnitOutage Number Unit Status*

Generation Affecting Total Downtime Action Required Comments

Responsible Person(s)

OOS EST RTSSPVP002 Chino Generation Outages

Business Operation Date 9/29/09 1 PO/SO X 11/19/09 11:46 11/19/09 12:29 0:43 hrsElectrical

Interconnection TestSCE and US�Most were onsite to conduct a two inverter , site and Declazsubstation operational impact test.

KB

2 SO 2/3/10 6:05 2/3/10 7:00 0:55 hrs Replace fuses Morrow Meadows was onsite to replace fuses on Inverter B. KB

Total Outages 2

Chino Availability Factor 100.0% Updated: March 24 2010

Availability Factor Calculation17:12 Hrs1512100.0%

Daily Solar Generation Outage

Outage Dates

* ON : on�line, dispatched per schedule unless noted; OFF : off�line, dispatched per schedule unless noted; FO : forced outage; SO : scheduled outage; TBD : To Be Determined; RO: Reporting Outage; PO : Partial Outage; DCE : Data Communications Error;

Appendix VIII-A

Appendix VIII-B

Appendix VIII-C

Appendix VIII-D

Appendix VIII-E

Appendix VIII-F

Appendix VIII-G

REDACTED

Appendix VIII-H

REDACTED

Appendix VIII-I

REDACTED

Appendix VIII-J

REDACTED

Appendix VIII-K

REDACTED

Appendix VIII-L

REDACTED

Appendix IX-A

2009 ERRA PURPA Project List 1

Southern California Edison Company LIST OF PURPA PROJECTS

2009 ERRA As of December 31, 2009

QFID PROJECT NAME EXECUTION STATUS

1005 Generating Resources Recovery Partners, L.P. D.93-04-006 D.04-01-050 D.06-01-007

1007 Royal Farms #1 D.93-04-006 1009 L.A. County Sanitation. Dist. #2 (Puente Hills A) D.93-04-006 1010 Brea Power Partners, L.P. Terminated – 07/08/07

1011 City of Oxnard Terminated – 07/15/96 1012 City of Palm Springs Terminated – 12/17/03 1015 Aliso Water Management Agency Terminated – 02/27/02 1018 Bio-Energy General Partners, L.P. (Penrose) Terminated – 05/11/06 1022 Bio-Energy General Partners, L.P. (Toyon) Terminated – 07/10/06 1023 Delano Energy Company, Incorporated Terminated – 12/31/99 1024 West Coast Cogeneration, Incorporated Terminated – 07/17/95 1026 Commerce Refuse to Energy/City of Commerce D.93-04-006 1028 City of Long Beach/SERRF D.93-04-006 1029 Gas Recovery Systems/Coy Canyon Landfill Terminated – 06/14/00 1038 Colmac Energy, Incorporated D.98-09-040 1040 O'Brien Energy Systems, Incorporated (Corona) Terminated – 09/05/05 1043 Imperial Resource Recovery Associates Terminated – 01/31/00 1077 L.A. County Sanit. Dist. #2 (Spadra Landfill) D.93-04-006 1082 L.A. County Sanit. Dist. #2 (Palos Verdes #2) Terminated – 12/20/08 1087 Royal Farms #2 D.93-04-006 1088 Sharp Ranch Terminated – 04/20/09 1090 L.A. County Sanit. Dist. #2 (Puente Hills B) D.93-04-006 1096 West Coast Cogen, Incorporated (Ph. II) Terminated – 10/04/96 1098 County Sanit. Dist. of Orange Cty (Huntington Bch.) Terminated – 06/30/06 1099 Chino Basin Municipal Water District D.99-03-022 1100 City of Tulare Terminated – 04/22/99 1102 Western Rock Products D.93-04-006 1103 Minnesota Methane-Visalia Terminated – 12/31/06 1104 Minnesota Methane-Tajiguas Terminated – 06/05/07 1105 Minnesota Methane-Lopez Terminated – 08/26/06 1106 Minnesota Methane-Yolo Terminated – 12/31/06 1107 Minnesota Methane-Woodville Terminated – 12/31/06 1108 Minnesota Methane-Teapot D.99-03-022 1109 Minnesota Methane-Highgrove Terminated – 12/30/01 1110 West Coast Cogeneration (BKK I) Terminated – 12/31/06 1111 West Coast Cogeneration (BKK II) Terminated – 12/31/06 1112 Minnesota Methane (BKK III) Terminated – 12/30/01


1114 Inland Empire Utilities Agency Terminated – 03/04/99 1115 Wheelabrator (Martell) Terminated – 12/30/01 1132 Toyon Landfill Gas Conversion, LLC D.07-12-027 1133 Cambrian Energy Woodville, LLC D.07-12-038 2003 Rhone-Poulenc Basic Chemical Company D.98-04-023 2006 Vintage Petroleum Terminated – 10/29/00 2007 North American Chemical Company

Searles Valley Minerals Operations, Inc. D.93-04-006 D.04-01-050 D.06-01-007

2008 Riverside Cement Company Terminated – 01/09/02 2010 Loma Linda University #1 D.93-04-006 2013 Procter & Gamble (Oxnard #1) Terminated – 04/16/00 2014 FPB Cogeneration Partners, L.P. Terminated – 07/30/01 2015 Arco Wilmington Calciner Terminated – 03/16/00 2019 U.S. Borax, Inc. D.04-01-050

D.06-01-007 2023 Sunlaw Cogeneration Partners I Terminated – 01/03/99 2025 North American Chemical Company D.93-04-006 2027 Pacific Southwest Realty Company D.93-04-006 2031 Paper Pak Products, Incorporated Terminated – 04/04/07 2034 Kern River Cogeneration Company (Omar Hill) Terminated – 08/09/05 2037 Ontario Cogeneration, Incorporated (Sunkist) Terminated – 07/31/08 2040 City of Palm Springs (Municipal Complex) Terminated – 09/05/05 2041 City of Palm Springs (Sunrise Plaza) Terminated – 09/30/05 2042 O.L.S. Energy Co.-Camarillo-State Hospital D.99-03-022 2043 O.L.S. Energy Co-Chino-Men’s Institute D.99-03-022 2044 Kaweah Delta District Hospital Terminated – 07/10/02 2045 Inland Container Corporation D.93-04-006 2049 AES Placerita, Incorporated D.93-04-006 2050 Simpson Paper Company D.93-04-006 2053 Watson Cogeneration Company D.93-03-021

D.07-09-040 2055 Willamette Industries, Incorporated D.93-04-006 2058 Sycamore Cogeneration Company D.93-03-021

D.07-09-040 2064 Wheelabrator Norwalk Energy Company, Inc. D.93-04-006 2066 Glendora High School (USD) Terminated – 09/21/09 2067 Harbor Cogeneration Company Terminated – 02/15/99 2069 Smurfit Newsprint Corporation Terminated – 02/14/06 2071 Ace Cogeneration Company D.98-04-023 2072 Procter & Gamble (Oxnard #2) D.93-04-006 2073 Rockwell International Terminated – 10/22/97 2074 San Antonio Community Hospital Terminated – 03/21/01 2076 Midway Sunset Cogeneration Company D.93-03-021 2077 Rio Bravo Jasmin D.93-04-006 2078 Mojave Cogeneration Company D.98-04-023 2081 Corona Energy Partners, Limited D.93-04-006 2082 Container Corporation of America Terminated – 08/24/01


2083 O’Brien California Cogen Limited (Cal Milk) Terminated – 08/31/99 2085 The Episcopal Home Terminated – 11/13/07 2087 Carson Cogeneration Company (Ice Haus) D.93-04-006 2101 Exxon Company U.S.A. D.99-03-022 2102 Point Arguello Pipeline Company Terminated – 04/15/01 2155 Chevron, U.S.A., Incorporated #2 D.93-04-006 2169 Rio Hondo Community College District Terminated – 08/28/97 2178 Claremont Tennis Club D.93-04-006 2180 County of Los Angeles D.93-04-006 2195 Tulare, County of, Detention Facility Terminated – 11/12/06 2198 Turbine Tech Terminated – 06/20/99 2205 E. F. Oxnard, Incorporated D.98-04-023 2206 Arco Oil & Gas Co – Placerita I D.93-04-006 2207 Arco Oil & Gas Co – Placerita II Terminated – 05/30/02 2210 Petrominerals Corporation D.93-04-006 2212 Twin Palms Sanitarium Terminated – 12/22/04 2213 Rancho Simi Recreation & Park Dist. Project #1 D.93-04-006 2221 Baldwin Park High School D.93-04-006 2222 Baldwin Park Unif. School Dist. – Sierra Vista H.S. D.93-04-006 2223 EUA/Onsite Cogen, Limited (Regents Point) Terminated – 02/25/07 2224 Berry Petroleum Company (Newhall I) D.04-01-050

D.06-01-007 2236 Rancho Simi Recreation & Park Dist. Project #2 D.93-04-006 2238 Hammitt, Andrew G. Terminated – 12/21/99 2258 Vanguard/Anodyne D.93-04-006 2260 Peterson Ind./5 Points Maytag Terminated – 04/16/96 2265 Cogenic – Cal Lutheran Terminated – 03/01/07 2266 Transamerican Plastics Terminated – 06/27/96 2269 Vanguard Electronic Plating Terminated – 04/28/05 2278 Santa Monica Hotel Assoc. Limited – Bay Hotel Terminated – 10/02/00 2300 El Rancho School Dist. (El Rancho High School) Terminated – 07/02/03 2306 Patrick, Philip – Laundry – Ontario I D.93-04-006 2308 Pitiak, Joseph – Laundry – Corona Terminated – 07/01/06 2311 Azusa Unif. School Dist./Gladstone High School Terminated – 04/20/09 2314 Micro Utility Partners Terminated – 02/25/07 2316 American Private Ventures Terminated – 04/06/97 2318 Redlands YMCA Terminated – 02/20/03 2323 Micro Utility Partners (Lake Arrowhead Hilton) Terminated – 02/25/07 2327 Micro Utility Partners of America (Safe Plating) Terminated – 03/01/07 2339 Micro Utility Partners of America (Foss Plating) Terminated – 11/10/05 2343 Micro Utility Partners of America Terminated – 04/20/00 2347 The Amer. Cornerstone Corp. – Pl Vly Hosp. Terminated – 04/30/05 2348 The Amer. Cornerstone Corp. – St. Joseph Hosp. Terminated – 04/07/05 2349 Micro Utility Partners of America (Quaker) Terminated – 02/25/07 2366 Omni Metal Finishing Terminated – 01/21/07 2374 American Cornerstone Countryside Inn Terminated – 04/10/05 2378 Falcon Foam Plastics Terminated – 07/29/98 2382 Unocal Research Terminated – 09/24/99


2384 CES Energy – Corona Ltd (Pacific Clay) Terminated – 02/25/99 2389 Whittier Unif. High School Dist. (La Serna H.S.) Terminated – 09/12/97 2390 EUA/FRC II Enrgy Assoc. (Monterey Cntry Club) Terminated – 09/29/99 2392 EUA/FRC II Enrgy Assoc. (Palm Vly Cntry Club) Terminated – 09/29/99 2394 Rimrock Village Partnership D.93-03-021 2396 South End Racquet & Health Club Terminated – 05/02/09 2407 EUA/FRC II Enrgy Assoc. (Vintage Cntry Club) Terminated – 09/17/98 2410 Oxnard High School Terminated – 09/18/99 2411 Hueneme High School D.98-04-023 2453 Decogen, Incorporated Terminated – 11/30/03 2460 Reclamation Plant #1 – Fountain Valley Terminated – 03/08/09 2463 All Metals Processing of Orange County, Inc. Terminated – 07/28/05 2474 L.A. County Sanitation District Terminated – 12/08/00 2481 Chevron USA D.99-03-022 2482 Cogen Partners Southwest. LTD III Terminated – 12/30/01 2483 Culver City Muni Pool Terminated – 12/30/012484 Culver City City Hall Terminated – 12/30/012485 Culver City Police Station Terminated – 12/30/012486 Culver City Vets Building Terminated – 12/30/012487 Monterey Park Muni Pool Terminated – 12/30/012489 North American Cogen. Fellows D.00-02-048 2491 Hanford High School D.00-10-047 2717 Kern River Cogeneration Company Terminated – 05/31/06 2802 Palm Springs, City of (Municipal Complex) D.06-11-016 2803 Palm Springs, City of (Sunrise Plaza) D.06-11-016 3001 Heber Field Company D.93-04-006 3002 Geo East Mesa Electric Company Terminated – 03/31/94 3003 Mammoth Pacific #1 D.93-04-006 3004 Del Ranch, Limited (Niland #2) D.93-03-021 3006 Vulcan/BN Geothermal Power (Niland #1) D.93-03-021 3008 Coso Finance Partners (Navy I) D.93-04-006 3009 Elmore, Limited (Niland #3) D.93-03-021 3010 Ormesa I Terminated – 02/28/07 3011 Oxbow Geothermal Corporation D.93-04-006 3012 Ormesa Geothermal II Terminated – 02/28/07 3017 Beowawe Geothermal Power Company Terminated – 12/31/05 3018 Pacific Lighting Energy Systems/Casa Diablo D.98-04-023 3021 Second Imperial Geothermal Company D.99-03-022 3025 Salton Sea Power Generation L.P. #3 D.93-04-006 3026 Leathers, L.P. (Niland #4) D.93-03-021 3027 Mammoth Pacific #2 D.98-04-023 3028 Salton Sea Power Generation L.P. #2 D.98-04-023 3029 Coso Power Developers (Navy II) D.93-04-006 3030 Coso Energy Developers (BLM) D.93-04-006 3039 Salton Sea Power Generation L.P. #1 D.93-04-006 3050 Fish Lake Power/Salton Sea Power D.95-04-057 3051 Mammoth Pacific, III D.99-03-022 4003 City of La Habra Terminated – 07/27/98


4004 Hi Head Hydro, Incorporated D.93-04-006 4006 Henwood Associates – Unit 1 (Millner Creek) Terminated – 11/12/09 4007 Lake Hemet MWD (Unit 1) Terminated – 06/14/04 4008 Desert Power Company D.93-04-006 4009 Cucamonga County Water Terminated – 07/26/00 4010 Calleguas MWD – Unit 1 (Conejo) D.93-04-006 4011 San Gabriel Valley MWD Terminated – 06/30/064012 City of Santa Barbara (Cater Project) Terminated – 11/23/984013 Tehachapi Cummings/Co Water District D.93-04-006 4014 San Bernardino MWD (Unit 1, Site 1720) D.93-04-006 4017 Irvine Ranch Water District D.04-01-050

D.06-01-007 4019 City of Upland Terminated – 08/11/98 4020 Lake Hemet MWD (Unit 2) Terminated – 04/04/04 4021 City of Buena Park Terminated – 09/19/96 4022 Calleguas MWD - Unit 2 (Chatsworth) D.93-04-006 4025 Desert Water Agency (White Water) D.93-04-006 4026 Desert Water Agency (Snow Creek) D.93-04-006 4028 Lower Tule River Irrigation District/Lake Success D.93-04-006 4029 San Gabriel Hydro Partnership D.93-04-006 4030 Daniel M. Bates, et al. D.93-04-006 4031 Richard Moss D.93-04-006 4034 Central Hydroelectric/Isabella Hydro D.93-04-006 4035 Three Valleys MWD (Fulton Road) D.93-04-006 4036 Three Valleys MWD (Miramar) D.93-04-006 4037 Three Valleys MWD (Williams) D.93-04-006 4039 Kaweah River Power Authority (Terminus) D.98-04-023 4049 G Squared Energy No. 2 (Alamitos Barrier) Terminated – 12/03/02 4050 Hydro Electric Construction (Domin Gap Barrier) Terminated – 12/03/02 4051 John E. Howard/Montecito Water District D.93-04-006 4052 Calleguas MWD - Unit 3 (Santa Rosa) D.93-04-006 4055 Goleta Water District D.93-04-006 4056 City of El Segundo Terminated – 12/05/98 4058 United Water Conservation District D.93-04-006 4071 Deep Springs College D.93-04-006 4076 Camrosa County Water District D.93-04-006 4100 San Bernardino MWD Unit 3 (Site 2100) D.93-04-006 4137 Fullerton Hydro Partners D.89-05-064 4147 Monte Vista Water District D.98-04-023 4150 WFA Station I - Upland D.99-03-022 4152 Calleguas MWD D.99-03-022 5005 Daggett Leasing Corporation (SEGS)

1 D.96-07-047 5010 Curtis, Edwin D.93-04-006 5017 Luz Solar Partners Limited III D.93-04-006 5018 Luz Solar Partners Limited IV D.93-04-006

1

Original contracts for RAP ID 5005 and 5006 approved in D.93-04-006.


5019 Luz Solar Partners Limited V D.93-04-006 5020 Luz Solar Partners Limited VI D.93-04-006 5021 Luz Solar Partners Limited VII D.93-04-006 5050 Luz Solar Partners Limited VIII D.93-04-006 5051 Luz Solar Partners Limited IX D.98-04-023 5071 Taco Loco Terminated – 05/14/00 5072 Michael Pierson D.99-03-022 5073 Dan Moore Hollister Ranch D.99-11-022 5074 Palm Desert Hydrogen Ranch D.99-11-022 5078 Bentley Mills D.00-10-047 5233 Sierra SunTower, LLC Res. E-4295 6004 VMSO IV Corporation - Cabazon Wind Park D.93-04-006 6006 Mogul Wind D.93-04-006 6007 Mesa Wind Developers Terminated – 06/22/05 6009 San Gorgonio Wind Farms, Incorporated (WW I) D.93-04-006 6010 Zond Systems, Incorporated (Phase II) Terminated – 07/09/97 6011 Boxcar I Power Purchase Contract Trust D.93-04-006 6012 Great American Industries, Incorporated D.93-04-006 6024 Cannon Capital Group D.93-04-006 6029 Coram Energy LLC D.04-01-050

D.06-01-007 6030 Windpower Partners, 1993, L.P., Incorporated D.93-04-006 6031 EUI Management Ph, Incorporated D.93-04-006 6034 So Calif Sunbelt Dev, Incorporated (Mojave) Terminated – 08/08/02 6035 Windpower Partners, 1993, L.P. (Whitewater) D.93-04-006 6036 Section 28 Trust (Sandberg III) Terminated – 10/30/00 6037 Tehachapi Power Purchase Contract Trust D.93-04-006 6039 Zond Systems, Incorporated (VGI) D.93-04-006 6040 Zond Systems, Incorporated (VGII) D.93-04-006 6041 Zond Systems, Incorporated (VGIII) D.93-04-006 6042 Zond Systems, Incorporated (VGIV) D.93-04-006 6043 Zond Windsys Partners 85-A D.93-04-006 6044 Zond Windsys Partners 85-B D.93-04-006 6051 Phoenix Energy, Limited D.93-04-006 6052 Altech Energy, Limited (II) D.93-04-006 6053 Difwind Farms Limited V D.93-04-006 6054 Wind Farm Management, Incorporated Terminated – 12/31/03 6055 Coram Energy Group, Limited D.93-04-006 6056 So Calif Sunbelt Dev (Edom Hill) D.93-04-006 6057 Flowind Corporation (Flowind III) D.93-04-006 6058 Windustries, Incorporated D.93-04-006 6060 Calwind Resources, Incorporated D.93-04-006 6061 Windridge, Incorporated (Willow Wind) D.93-04-006 6062 Energy Development & Const. Corp. (Karen) D.93-04-006 6063 Desert Winds I Power Purchase Contract Trust D.93-04-006 6064 Section 7 Trust (Whitewater II) D.93-04-006 6065 Sky River Partnership (W I) D.98-09-040 6066 Sky River Partnership (W II) D.98-09-040


6067 Sky River Partnership (W III) D.98-09-040 6087 Altech Energy, Limited (III) D.93-04-006 6088 Difwind Partners, Limited D.93-04-006 6089 CTV Power Purchase Contract Trust D.93-04-006 6090 Alta Mesa Power Purchase Contract Trust D.93-04-006 6091 Flowind Corporation (Flowind IV) D.93-04-006 6092 Cannon/CVP Power Purchase Contract Trust D.93-04-006 6094 San Jacinto Power Corporation D.93-04-006 6095 Gael Energy, L.P. D.98-09-040 6096 Westwind Trust D.93-04-006 6097 Boxcar II Power Purchase Contract Trust D.93-04-006 6098 Meridian Trust Company of California D.98-09-040 6102 VG Phase IV Partnership D.98-09-040 6103 VG Phase IV Partnership D.98-09-040 6104 VG Phase IV Partnership D.98-09-040 6105 Zond Systems, Incorporated (Monolith X) D.93-04-006 6106 Zond Systems, Incorporated (Monolith XI) D.93-04-006 6107 Zond Systems, Incorporated (Monolith XII) D.93-04-006 6108 Zond Systems, Incorporated (Mono XIII) D.93-04-006 6111 Zond Systems, Incorporated (Northwind I) D.93-04-006 6112 Painted Hills Wind Developers D.93-04-006 6113 Desert Winds II Power Purchase Contract Trust D.98-04-023 6114 Desert Winds III Power Purchase Contract Trust D.93-04-006 6118 Windpower Partners 1993, L.P. (Riverview) D.93-04-006 6120 Bob Mallicoat Terminated – 12/03/03 6213 Meridian Trust Company of California D.93-04-006 6236 Kenetech Windpower, Incorporated (Arbutus) D.98-04-023 6308 PAMC Management Corp. D.06-11-016 7001 Honda Performance D.99-03-022 7002 Rocketdyne Terminated – 04/09/98

Appendix IX-B

ERRA PURPA PAYMENTSUMMARY TABLE

January 1 - December 31, 2009

CONFIDENTIALTHIS DOCUMENT PROVIDED SUBJECT TO PUBLICUTILITIES CODE §583 GENERAL ORDER NO. 66C.

- PUBLIC DISCLOSURE RESTRICTED -

This Table represents payments to RPSA projects covering 12 months, as discussed in Chapter IX.The figures in this Table show:Column (3), total energy (kWh) delivered by the PURPA projects to SCE during the Record Period;

(i) Capacity repayment due to derate(ii) Payments by SCE for transmission services(iii) Changes to any Payment Tracking Account (PTA) balances during the Record Period

The PTA is an interest bearing account created pursuant to the terms of some specially negotiatedPURPA contracts to track the difference between the contract's price and SCE's published avoided cost

1 2 3 4 5 7 8

RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)

Capacity Payment Subtotal(4)

Other Total Payment1005 RSO1 12,446,178 $541,719.96 $25,473.89 $567,193.85 $0.00 $567,193.851007 SO3 101,507 $3,941.31 $159.10 $4,100.41 $0.00 $4,100.411009 NEG 5,601,626 $350,849.77 $12,459.83 $363,309.60 $0.00 $363,309.601026 NEG 72,310,260 $6,521,159.65 $1,848,850.42 $8,370,010.07 $0.00 $8,370,010.071028 NEG 229,022,748 $20,579,498.56 $4,418,931.06 $24,998,429.62 $0.00 $24,998,429.621038 SO4 356,681,000 $22,313,430.00 $10,236,148.68 $32,549,578.68 $0.00 $32,549,578.681068 NEG $0.00 $0.00 $0.00 $0.00 $0.001077 NEG 44,460,408 $2,814,289.94 $1,312,994.10 $4,127,284.04 $0.00 $4,127,284.041087 SO3 163,284 $7,206.23 $155.74 $7,361.97 $0.00 $7,361.971088 SO3 $0.00 $0.00 $0.00 $0.00 $0.001090 NEG 361,764,777 $22,752,707.38 $9,508,407.24 $32,261,114.62 $0.00 $32,261,114.621099 SO1 1,269,100 $54,416.96 $2,383.64 $56,800.60 $0.00 $56,800.601102 SO1 108 $8.22 $0.03 $8.25 $0.00 $8.251126 NEG 19,368 $1,030.87 $1.93 $1,032.80 $0.00 $1,032.801132 RSO1 10,096,000 $453,054.06 ($607.50) $452,446.56 $0.00 $452,446.561133 RSO1 1,048,058 $48,406.94 $317.09 $48,724.03 $0.00 $48,724.032003 SO1 7,758,448 $311,206.67 $20,105.94 $331,312.61 $0.00 $331,312.612005 NEG $0.00 $0.00 $0.00 $0.00 $0.002007 RSO1 286,032 $8,953.79 $1,835.10 $10,788.89 $0.00 $10,788.892010 SO1 2,513,724 $96,769.09 $3,632.34 $100,401.43 $0.00 $100,401.432019 RSO1 170,969,454 $7,012,046.98 $352,854.47 $7,364,901.45 $0.00 $7,364,901.452025 NEG 116,901,342 $6,749,806.71 $1,683,181.41 $8,432,988.12 $0.00 $8,432,988.122042 NEG 213,981,924 $9,238,834.02 $4,878,123.66 $14,116,957.68 $0.00 $14,116,957.682043 NEG 203,344,164 $8,674,412.16 $4,745,102.88 $13,419,515.04 $0.00 $13,419,515.042045 SO4 100,567,800 $4,264,313.17 $2,737,483.69 $7,001,796.86 $0.00 $7,001,796.862050 NEG 122,646,840 $6,020,007.14 $6,241,768.67 $12,261,775.81 $0.00 $12,261,775.812053 NEG 2,178,683,640 $82,132,607.10 $31,249,178.42 $113,381,785.52 $0.00 $113,381,785.522055 SO4 83,478,576 $3,645,502.35 $2,702,730.69 $6,348,233.04 $0.00 $6,348,233.042057 SO3 $0.00 $0.00 $0.00 $0.00 $0.002058 NEG 2,129,013,030 $80,006,891.55 $27,475,934.17 $107,482,825.72 $0.00 $107,482,825.722060 SO1 $0.00 $0.00 $0.00 $0.00 $0.002064 NEG 91,315,728 $4,821,413.63 $5,021,807.13 $9,843,220.76 $0.00 $9,843,220.762066 SO3 $0.00 $0.00 $0.00 $0.00 $0.002071 NEG 783,300,456 $49,056,329.64 $20,087,874.57 $69,144,204.21 $0.00 $69,144,204.21

Column (7), "Other," includes total additional power purchase contract related Record Period payments to the projects or to SCE.These payments relate to the following categories:

Columns (4) and (5), total Record Period payments by SCE to the PURPA projects for energy and capacity.

Page 1





RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment2072 SO4 383,847,540 $16,079,460.25 $11,416,103.19 $27,495,563.44 $0.00 $27,495,563.442076 NEG 1,698,905,088 $64,980,372.99 $19,755,480.36 $84,735,853.35 $0.00 $84,735,853.352077 SO4 292,514,760 $18,303,922.60 $7,100,194.26 $25,404,116.86 $0.00 $25,404,116.862078 NEG 339,716,214 $13,915,403.41 $10,910,303.09 $24,825,706.50 $0.00 $24,825,706.502081 SO2 302,342,063 $12,925,799.64 $6,797,694.69 $19,723,494.33 $0.00 $19,723,494.332087 SO2 369,365,292 $15,811,058.02 $9,190,744.25 $25,001,802.27 $0.00 $25,001,802.272101 SO1 9,265,196 $389,627.02 $15,803.66 $405,430.68 $0.00 $405,430.682149 SO3 $0.00 $0.00 $0.00 $0.00 $0.002155 SO1 29,879,010 $1,325,720.71 $25,662.04 $1,351,382.75 $0.00 $1,351,382.752178 SO1 $0.00 $0.00 $0.00 $0.00 $0.002180 SO2 177,049,512 $7,382,348.03 $3,854,652.01 $11,237,000.04 (i)2205 NEG 196,571,886 $9,512,452.11 $10,405,613.43 $19,918,065.54 $0.00 $19,918,065.542206 SO2 159,433,488 $6,431,130.48 $2,004,264.85 $8,435,395.33 $0.00 $8,435,395.332210 SO1 68,435 $3,496.41 $65.18 $3,561.59 $0.00 $3,561.592213 SO3 143,542 $6,199.70 $164.57 $6,364.27 $0.00 $6,364.272215 NEG $0.00 $0.00 $0.00 $0.00 $0.002224 RSO1 144,234,756 $5,984,004.78 $348,699.69 $6,332,704.47 $0.00 $6,332,704.472236 SO3 37,972 $1,627.05 $40.84 $1,667.89 $0.00 $1,667.892258 SO3 $0.00 $0.00 $0.00 $0.00 $0.002311 SO3 $0.00 $0.00 $0.00 $0.00 $0.002344 SO3 $0.00 $0.00 $0.00 $0.00 $0.002359 SO3 $0.00 $0.00 $0.00 $0.00 $0.002386 SO3 $0.00 $0.00 $0.00 $0.00 $0.002394 SO1 $0.00 $0.00 $0.00 $0.00 $0.002396 SO3 $15.70 $0.00 $15.70 $0.00 $15.702401 SO1 $0.00 $0.00 $0.00 $0.00 $0.002411 SO3 $0.00 $0.00 $0.00 $0.00 $0.002413 SO1 $0.00 $0.00 $0.00 $0.00 $0.002430 SO1 $0.00 $0.00 $0.00 $0.00 $0.002441 SO1 $0.00 $0.00 $0.00 $0.00 $0.002460 SO1 11,322 $708.84 $3.19 $712.03 $0.00 $712.032462 SO1 $0.00 $0.00 $0.00 $0.00 $0.002475 SO1 7,557,624 $354,490.33 $792.84 $355,283.17 $0.00 $355,283.172479 SO1 10,509 $448.78 $23.53 $472.31 $0.00 $472.312480 SO1 $0.00 $0.00 $0.00 $0.00 $0.002490 SO1 666 $37.40 $1.67 $39.07 $0.00 $39.072801 NEG 1,241,076,534 $41,100,106.77 $24,332,665.88 $65,432,772.65 $0.00 $65,432,772.652802 RSO1 242,704 $10,370.29 $105.06 $10,475.35 $0.00 $10,475.352803 RSO1 1,407,880 $60,841.01 $535.80 $61,376.81 $0.00 $61,376.812804 NEG 20,340 $899.77 $26.40 $926.17 $0.00 $926.173001 NEG 363,692,000 $22,716,731.05 $6,743,223.51 $29,459,954.56 $0.00 $29,459,954.563003 NEG 44,100,360 $2,754,658.81 $818,641.95 $3,573,300.76 $0.00 $3,573,300.763004 NEG 344,347,000 $21,535,341.20 $8,057,405.10 $29,592,746.30 $0.00 $29,592,746.303006 SO4 301,532,000 $18,853,428.12 $5,625,836.65 $24,479,264.77 $0.00 $24,479,264.773008 SO4 598,673,016 $37,432,221.38 $13,032,254.27 $50,464,475.65 $0.00 $50,464,475.653009 SO4 337,096,000 $21,071,750.95 $8,063,460.50 $29,135,211.45 $0.00 $29,135,211.453011 SO4 424,031,652 $26,520,783.67 $10,831,958.36 $37,352,742.03 $0.00 $37,352,742.03

Page 2





RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment3018 SO4 103,730,976 $6,435,763.11 $2,158,275.26 $8,594,038.37 $0.00 $8,594,038.373021 NEG 251,532,000 $15,812,742.87 $6,967,380.57 $22,780,123.44 $0.00 $22,780,123.443025 SO4 387,876,000 $24,275,473.15 $9,529,109.95 $33,804,583.10 $0.00 $33,804,583.103026 SO4 333,363,000 $20,862,922.68 $7,509,493.70 $28,372,416.38 $0.00 $28,372,416.383027 SO4 93,418,428 $5,781,800.73 $1,891,869.33 $7,673,670.06 $0.00 $7,673,670.063028 SO4 135,451,000 $8,468,162.08 $3,309,900.00 $11,778,062.08 $0.00 $11,778,062.083029 SO4 578,120,906 $36,151,759.82 $13,635,741.74 $49,787,501.56 $0.00 $49,787,501.563030 SO4 513,471,598 $32,173,309.94 $12,433,746.54 $44,607,056.48 $0.00 $44,607,056.483039 NEG 81,437,000 $7,401,558.69 $2,222,997.40 $9,624,556.09 $287,468.00 (ii) $9,912,024.093050 NEG 354,208,000 $29,115,121.41 $7,297,896.00 $36,413,017.41 $0.00 $36,413,017.413104 SO4 423,193,000 $26,387,313.35 $8,501,804.67 $34,889,118.02 $0.00 $34,889,118.024004 NEG 1,909,037 $114,542.22 $27,741.84 $142,284.06 $0.00 $142,284.064006 NEG 807,575 $40,346.69 $13,447.22 $53,793.91 $0.00 $53,793.914008 NEG 1,248,498 $49,342.64 $4,557.03 $53,899.67 $43,545.63 (iii) $97,445.304010 SO4 47,622 $2,306.94 $1,793.51 $4,100.45 $0.00 $4,100.454013 SO3 $0.00 $0.00 $0.00 $0.00 $0.004014 SO3 308,962 $12,561.64 $1,392.91 $13,954.55 $0.00 $13,954.554016 SO4 825,202 $33,997.20 $17,890.27 $51,887.47 $0.00 $51,887.474017 RSO1 $0.00 $0.00 $0.00 $0.00 $0.004022 SO4 6,674,533 $277,234.62 $144,591.84 $421,826.46 $0.00 $421,826.464025 SO4 1,302,012 $50,290.44 $33,816.02 $84,106.46 $0.00 $84,106.464026 SO4 533,797 $22,494.63 $12,791.73 $35,286.36 $0.00 $35,286.364028 SO4 1,220,406 $45,108.17 $31,453.77 $76,561.94 $0.00 $76,561.944029 SO4 4,422,652 $181,376.03 $234,643.14 $416,019.17 $0.00 $416,019.174030 SO4 483,896 $23,485.14 $11,410.67 $34,895.81 $0.00 $34,895.814031 SO4 379,080 $15,324.21 $7,781.66 $23,105.87 $0.00 $23,105.874032 SO3 $0.00 $0.00 $0.00 $0.00 $0.004034 SO4 12,760,032 $480,285.21 $746,231.52 $1,226,516.73 $0.00 $1,226,516.734035 SO4 1,228,237 $49,847.97 $30,235.07 $80,083.04 $0.00 $80,083.044036 SO4 1,379,784 $53,939.32 $32,393.32 $86,332.64 $0.00 $86,332.644037 SO4 1,742,334 $70,710.40 $45,855.32 $116,565.72 $0.00 $116,565.724039 SO4 34,770,402 $1,310,783.02 $1,696,804.64 $3,007,587.66 $0.00 $3,007,587.664051 SO4 578,504 $23,544.51 $17,009.92 $40,554.43 $0.00 $40,554.434052 SO4 381,019 $15,322.12 $14,531.81 $29,853.93 $0.00 $29,853.934054 SO3 3,048 $116.98 $1.19 $118.17 $0.00 $118.174055 SO3 112,878 $3,874.78 $1,067.98 $4,942.76 $0.00 $4,942.764058 SO1 $0.00 $0.00 $0.00 $0.00 $0.004071 SO3 6,048 $301.17 $0.66 $301.83 $0.00 $301.834076 SO3 $0.00 $0.00 $0.00 $0.00 $0.004100 SO3 183,255 $6,704.45 $96.14 $6,800.59 $0.00 $6,800.594137 SO2 781,458 $29,404.63 $3,170.90 $32,575.53 $0.00 $32,575.534145 SO3 $0.00 $0.00 $0.00 $0.00 $0.004147 SO1 18,073 $995.69 $4.63 $1,000.32 $0.00 $1,000.324150 SO1 $0.00 $0.00 $0.00 $0.00 $0.004152 SO1 773,784 $30,122.48 $2,729.37 $32,851.85 $0.00 $32,851.855005 NEG 42,394,194 $1,619,783.60 $5,344,210.21 $6,963,993.81 $0.00 $6,963,993.815010 SO3 2,602 $147.09 $0.26 $147.35 $0.00 $147.35

Page 3





RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment5017 SO4 83,767,716 $5,369,369.88 $5,090,907.75 $10,460,277.63 $0.00 $10,460,277.635018 SO4 82,743,804 $5,293,016.37 $5,077,436.34 $10,370,452.71 $0.00 $10,370,452.715019 SO4 77,574,960 $4,950,310.32 $5,351,295.31 $10,301,605.63 $0.00 $10,301,605.635020 SO4 86,948,856 $5,593,283.64 $5,800,824.03 $11,394,107.67 $0.00 $11,394,107.675021 SO4 82,706,868 $5,323,023.97 $5,755,745.52 $11,078,769.49 $0.00 $11,078,769.495050 SO2 186,881,472 $12,136,691.80 $15,617,122.79 $27,753,814.59 $0.00 $27,753,814.595051 SO2 196,759,656 $12,743,015.41 $17,544,543.05 $30,287,558.46 $0.00 $30,287,558.465066 SO3 $0.00 $0.00 $0.00 $0.00 $0.005233 NEG 24,054 $1,109.89 $435.98 $1,545.87 $0.00 $1,545.876004 SO4 85,058,532 $5,300,108.94 $1,135,481.96 $6,435,590.90 $0.00 $6,435,590.906006 NEG 9,162,884 $690,066.76 $0.00 $690,066.76 $0.00 $690,066.766009 NEG 7,483,662 $257,227.18 $33,469.76 $290,696.94 $0.00 $290,696.946011 SO4 11,798,776 $482,010.25 $198,351.58 $680,361.83 $0.00 $680,361.836012 NEG 2,859,818 $162,348.35 $15,629.58 $177,977.93 $0.00 $177,977.936019 SO4 9,090,960 $565,237.29 $171,582.92 $736,820.21 $0.00 $736,820.216024 SO4 147,275,633 $5,810,257.96 $2,708,426.75 $8,518,684.71 $0.00 $8,518,684.716029 RSO1 28,790,100 $1,154,607.68 $48,928.47 $1,203,536.15 $0.00 $1,203,536.156030 SO4 23,090,984 $1,436,014.42 $173,033.03 $1,609,047.45 $0.00 $1,609,047.456031 SO4 48,947,456 $3,026,034.25 $1,095,771.12 $4,121,805.37 $0.00 $4,121,805.376035 SO4 9,680,387 $598,392.47 $87,183.86 $685,576.33 $0.00 $685,576.336037 SO4 115,499,592 $7,075,830.61 $2,054,401.54 $9,130,232.15 $0.00 $9,130,232.156039 SO4 12,405,032 $501,908.08 $126,469.79 $628,377.87 $0.00 $628,377.876040 SO4 11,205,936 $451,027.96 $114,917.40 $565,945.36 $0.00 $565,945.366041 SO4 9,547,808 $391,699.63 $118,521.51 $510,221.14 $0.00 $510,221.146042 SO4 9,154,928 $367,037.13 $104,749.15 $471,786.28 $0.00 $471,786.286043 SO4 20,086,608 $795,772.74 $258,840.38 $1,054,613.12 $0.00 $1,054,613.126044 SO4 27,564,784 $1,112,640.14 $449,740.66 $1,562,380.80 $0.00 $1,562,380.80

Page 4





RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment6051 SO4 40,335,600 $1,544,386.42 $834,913.48 $2,379,299.90 $0.00 $2,379,299.906052 SO4 8,035,614 $313,001.86 $153,061.30 $466,063.16 $0.00 $466,063.166053 SO4 14,191,188 $544,502.99 $331,082.32 $875,585.31 $0.00 $875,585.316055 SO4 11,326,765 $457,532.57 $102,473.87 $560,006.44 $0.00 $560,006.446056 SO4 31,579,391 $1,933,668.27 $412,664.75 $2,346,333.02 $0.00 $2,346,333.026057 SO4 137,624,472 $8,518,043.22 $2,512,080.56 $11,030,123.78 $0.00 $11,030,123.786058 SO4 29,118,036 $1,789,928.31 $616,387.34 $2,406,315.65 $0.00 $2,406,315.656060 SO4 15,124,752 $625,904.57 $285,550.84 $911,455.41 $0.00 $911,455.416061 SO4 1,630,844 $69,679.97 $4,562.20 $74,242.17 $0.00 $74,242.176062 SO4 33,387,852 $1,332,480.01 $551,522.60 $1,884,002.61 $0.00 $1,884,002.616063 SO4 77,926,284 $4,765,862.95 $1,523,440.43 $6,289,303.38 $0.00 $6,289,303.386064 SO4 55,874,619 $2,132,388.25 $529,591.96 $2,661,980.21 $0.00 $2,661,980.216065 SO4 78,073,542 $4,801,347.97 $1,235,882.38 $6,037,230.35 $0.00 $6,037,230.356066 SO4 42,450,642 $2,595,597.75 $578,569.93 $3,174,167.68 $0.00 $3,174,167.686067 SO4 43,901,982 $2,683,684.06 $487,162.44 $3,170,846.50 $0.00 $3,170,846.506087 SO4 79,378,656 $2,925,396.52 $1,660,286.61 $4,585,683.13 $0.00 $4,585,683.136088 SO4 28,639,164 $1,062,693.19 $595,527.53 $1,658,220.72 $0.00 $1,658,220.726089 SO4 29,374,416 $1,133,608.56 $534,047.50 $1,667,656.06 $0.00 $1,667,656.066090 SO4 67,366,296 $2,629,772.60 $1,792,750.99 $4,422,523.59 $0.00 $4,422,523.596091 SO4 36,372,936 $2,249,653.92 $672,519.35 $2,922,173.27 $0.00 $2,922,173.276092 SO4 77,895,000 $5,471,226.18 $2,056,435.78 $7,527,661.96 $0.00 $7,527,661.966094 SO4 42,998,376 $1,658,876.18 $924,989.50 $2,583,865.68 $0.00 $2,583,865.686095 SO4 20,938,878 $801,463.19 $584,780.82 $1,386,244.01 $0.00 $1,386,244.016096 SO4 25,353,024 $1,002,866.05 $622,707.49 $1,625,573.54 $0.00 $1,625,573.546097 SO4 19,794,024 $820,671.47 $394,444.89 $1,215,116.36 $0.00 $1,215,116.366098 SO4 3,348,672 $206,660.23 $76,425.25 $283,085.48 $0.00 $283,085.486102 SO4 16,245,800 $1,015,988.40 $237,120.27 $1,253,108.67 $0.00 $1,253,108.676103 SO4 12,877,112 $815,345.37 $212,922.12 $1,028,267.49 $0.00 $1,028,267.496104 SO4 15,548,352 $962,525.16 $186,827.67 $1,149,352.83 $0.00 $1,149,352.836105 SO4 9,967,536 $389,870.80 $135,889.49 $525,760.29 $0.00 $525,760.296106 SO4 8,783,488 $337,851.99 $124,487.32 $462,339.31 $0.00 $462,339.316107 SO4 10,400,600 $647,657.03 $149,448.42 $797,105.45 $0.00 $797,105.456108 SO4 7,656,384 $475,046.31 $99,734.92 $574,781.23 $0.00 $574,781.236111 SO4 8,995,160 $373,702.27 $118,473.34 $492,175.61 $0.00 $492,175.616112 SO4 36,333,432 $2,241,525.50 $466,173.74 $2,707,699.24 $0.00 $2,707,699.246113 SO4 199,357,560 $11,919,827.70 $3,831,516.13 $15,751,343.83 $0.00 $15,751,343.836114 SO4 77,884,884 $4,783,308.49 $1,714,847.95 $6,498,156.44 $0.00 $6,498,156.446118 SO4 8,582,299 $530,542.43 $80,296.62 $610,839.05 $0.00 $610,839.05

*6136 SO3 (383) ($57.17) ($57.17) ($57.17)6213 SO4 31,585,614 $1,962,930.73 $339,319.43 $2,302,250.16 $0.00 $2,302,250.166234 SO4 76,399,744 $4,749,021.66 $1,680,722.21 $6,429,743.87 $0.00 $6,429,743.876236 SO1 51,135,624 $2,050,833.64 $90,595.10 $2,141,428.74 $0.00 $2,141,428.746308 RSO1 57,227,814 $2,245,384.01 $114,723.63 $2,360,107.64 $0.00 $2,360,107.64197 21,507,134,084 $1,092,536,737.64 $476,626,349.62 $1,569,163,087.26 $1,568,910,179.94

*Reflects a prior year true up credit for a terminated project and is not reflected in the total project count.

Page 5

Appendix X-A

2009 ERRA RPS Project List 1

Southern California Edison Company LIST OF RPS PROJECTS

2009 ERRA As of December 31, 2009

RAP ID PROJECT NAME ADVICE LETTER/ APPLICATION/ DECISION/ OTHER

DATE

1091 North American Trading Res. E-3816 5/08/03 1093 Waste Management-El Sobrante Res. E-3809 1/30/03 1095 Waste Management-Simi Valley Res. E-3809 1/30/03 1193 WMES El Sobrante Pending1195 WMES Simi Valley Pending1207 Liberty I Biofuels Power Res. E-3934 6/30/05 1208 Sierra Biomass LLC Res. E-3934 6/30/05 1209 Imperial Valley Resource Recovery D.07-04-039 4/16/07 1210 MM Tajiguas Energy LLC D.07-04-038 4/16/07 1211 DESC Not Submitted 1212 Chateau Energy, Inc. D.07-08-028 2/23/09 1213 LA County Sanitation (Palos Verdes) Res. E-4125 5/29/08 1214 Flex LA Res. E-4159 9/18/08 1216 Flex Riverside Res. E-4159 9/18/08 1217 Imperial Valley Biopower Terminated 10/13/09 1219 FlexEnergy, LLC, Flex-Bernardino Res. E-4230 5/07/09 1220 FlexEnergy, LLC, FlexKern Res. E-4230 5/07/09 1221 Ventura Regional Sanitation District Res. E-4263 12/17/09 1223 Western Water and Power Production, LLC Pending 1225 Badlands Landfill (Riverside County San.

District) CREST

3052 Calpine Energy Services, L.P. Res. E-3809 1/30/03 3101 Green Borders Geothermal LLC Res. E-3934 6/30/05 3103 Coso Clean Power D.07-05-046 5/25/07 3106 Terra-Gen Dixie Valley Res. E-4126 3/13/08 3107 Geysers Power Co., LLC D.07-11-047 11/20/07 3108 Ormat Imperial, ORNI 18 Res. E-4126 3/13/08 3109 Geysers Power Company Res. E-4158 10/16/08 3110 Ormat Nevada, ORNI 21 Res. E-4183 7/31/08 3121 Orita Geothermal 1 LLC AL 2393-E 10/29/09 4005 Metropolitan Water District (MWD) Res. E-3809 1/30/03 4105 Metropolitan Water District Res. E-4186 9/04/08 5101 SES Solar One LLC Res. E-3957 10/27/05 5206 California Sunrise I Terminated 6/30/09 5207 FSE Blythe 1, LLC Res. E-4157 7/10/08 5208 Solar Partners I, LLC AL 2339-E 4/06/09 5210 Solar Partners X, LLC AL 2339-E 4/06/09 5211 Solar Partners XI, LLC AL 2339-E 4/06/09 5212 Solar Partners XII, LLC AL 2339-E 4/06/09 5213 Solar Partners XIII, LLC AL 2339-E 4/06/09

2009 ERRA RPS Project List 2

5214 Solar Partners XIV, LLC AL 2339-E 4/06/09 5215 Solar Partners XV, LLC AL 2339-E 4/06/09 5217 Desert Sunlight AL 2391-E-A 10/16/09 5218 Desert Stateline AL 2391-E-A 10/16/09 5231 CA Solar 10 AL 2374-E 8/21/09 5232 Ridgecrest AL 2374-E 8/21/09 5237 Kramer South, LLC Pending5238 North Edwards, LLC Pending5239 Boron Solar, LLC Pending5240 RE Rio Grande, LLC Pending5247 RE Rosamond Two, LLC Pending5249 RE Victor Phelan Solar One, LLC Pending5252 TA Antelope Pending5253 Sustainable Capital Energy Partners, LLC

(SCEP)Pending

5608 Gaskell Suntower Res. E-4188 12/04/08 6304 Mountain View Power Partners IV LLC Res. E-3934 6/30/05 6305 PPM Energy, Inc. Res. E-3963 12/01/05 Dillon Wind Res. E-4051 1/11/07 6306 Coram Energy Group LLC Terminated 8/12/09 6307 Aero Energy LLC Res. E-3934 6/30/05 6309 Terra-Gen 251 Wind LLC I D.07-05-046 5/25/07 6310 Terra-Gen 251 Wind LLC II D.07-05-046 5/25/07 6311 Ridgetop Energy, LLC I D.07-05-046 5/25/07 6312 Ridgetop Energy, LLC II D.07-05-046 5/25/07 6313 Alta Windpower Development, LLC D. 08-05-017 5/15/08 6314 Alta Windpower I D. 08-05-017 5/15/08 6315 Alta Windpower II D. 08-05-017 5/15/08 6316 Alta Windpower III D. 08-05-017 5/15/08 6317 Alta Windpower IV D. 08-05-017 5/15/08 6318 Alta Windpower V D. 08-05-017 5/15/08 6325 Granite Wind (RES Americas) Res. E-4125 5/29/08 6326 Rumorosa I (Baja Wind, LLC) Terminated 8/12/09 6329 AES SeaWest (Daggett Ridge) AL withdrawn 6330 Caithness – North Hurlburt Wind, LLC Res. E-4253 9/24/09 6331 Caithness – South Hurlburt Wind, LLC Res. E-4253 9/24/09 6332 Caithness – Horseshoe Bend Wind, LLC Res. E-4253 9/24/09 6333 AES Mountain View Power Partners, LLC Res. E-4248 6/18/09 6334 Goshen Phase II, LLC Res. E-4262 10/15/09 6335 Puget Sound Energy, Inc. Res. E-4244 6/18/09 6336 Echanis Wind Res. E-4293 12/17/09 6337 Puget Sound Energy II AL 2358-E-A 7/13/09 6338 PacifiCorp Res. E-4264 10/15/09 6340 Puget Sound Energy III Res. E-4300 12/17/09 6341 Sand Canyon of Tehachapi, LLC Pending6342 The Aeromen, LLC Pending6343 Clear Vista Ranch, LLC Pending

Appendix X-B

ERRA RPS PAYMENTSUMMARY TABLE




This Table represents payments to RPS projects covering 12 months, as discussed in Chapter X.The figures in this Table show:Column (3), total energy (kWh) delivered by the RPS Projects to SCE during the Record Period;

(i) Forfeited development fee (ii) Daily Liquidated Damages to extend the start-up deadline

(iii) Payments by SCE for transmission services(iv) Purchase is part of the Novation to the existing CDWR Mountain View Power Partners Agreement(v) Buyout agreements

1 2 3 4 5 6 7 8

RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment1093 RPSA -1095 RPSA1193 RSC5 - - - - - -1195 RSC5 - - - - - -1208 RPSA - - - - (i)1209 RPSA - ($219,560.00) (ii)1210 RPSA - -1212 RPSA - - - - - -1213 RPSA - - - - - -1214 RPSA - - - - - -1216 RPSA - - - - - -1217 RPSA - - - - (i)1219 RPSA - - - - - -1220 RPSA - - - - - -1221 RSC5 - -1225 CREST - -3101 RPSA - - - - - -3103 RPSA - - - - - -3106 RPSA - - - - - -3107 RPSA - -3108 RPSA - -3110 RPSA - - - - - -3115 RPSA - - - - - -3116 RPSA - - - - - -3121 RPSA - - - - - -

*4005 RPSA - - - - (iii)4105 RPSA - -4106 RPSA - -4107 RPSA 9 - -

Column (7), "Other," includes total additional power purchase contract-related Record Period payments to the Projects or to SCE.These payments relate to the following categories:

Columns (4) and (5), total Record Period payments by SCE to the RPS Projects for energy and capacity.

Page 1





RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment4108 RPSA - -5101 RPSA - - - - - -5206 RPSA - - - - (i)5207 RPSA - -5208 RPSA - - - - - -5210 RPSA - - - - - -5211 RPSA - - - - - -5212 RPSA - - - - - -5213 RPSA - - - - - -5214 RPSA - - - - - -5215 RPSA - - - - - -5217 RPSA - - - - - -5218 RPSA - - - - - -5231 RPSA - - - - - -5232 RPSA - - - - - -5237 RSC20 - - - - - -5238 RSC20 - - - - - -5239 RSC20 - - - - - -5240 RSC5 - - - - - -5247 RSC20 - - - - - -5249 RSC20 - - - - - -5252 RSC20 - - - - - -5253 RSC20 - - - - - -5608 RPSA - - - - - -6304 RPSA - - - - - -6305 RPSA - -6306 RPSA - - - - - -6307 RPSA - - - - - -6309 RPSA - - - - - -6310 RPSA - - - - - -6311 RPSA - - - - - -6312 RPSA - - - - - -6313 RPSA - - - - - -6314 RPSA - - - - - -6315 RPSA - - - - - -6316 RPSA - - - - - -6317 RPSA - - - - - -6318 RPSA - - - - - -6325 RPSA - - - - - -6326 RPSA - - - - - -6329 RPSA - - - - - -6330 RPSA - - - - - -

Page 2





RAP IDContract

Type(1)

Energy (kWh)(2)

Energy Payment(3)


Other Total Payment6331 RPSA - - - - - -6332 RPSA - - - - - -6333 RPSA - - - - - -6334 RPSA - - - - - -6335 RPSA - -6336 RPSA - - - - - -6337 RPSA - - - - - -6338 RPSA - -6340 RPSA - - - - - -6342 RSC5 - - - - - -8001 RPSA - - - - - -8004 RPSA - - - -8005 RPSA - - - - - -8006 RPSA - - - -8007 RPSA - - - -

WREGIS85 2,949,577,895 $184,205,671.99 $43,246.58 $184,248,918.57 $3,538,756.01 $187,787,674.58

*Reflects a prior year true up payment for a terminated project and is not reflected in the total project count.

Page 3

Appendix XV-A

DETAILED OVERVIEW OF ORIGINAL AND MRTU MARKET STRUCTURES 1

As explained below, the new MRTU market structure adds significant complexity to the market, and 2

in turn, to SCE’s internal processes. California has transitioned from a simple day-ahead structure that 3

required each market participant to balance supply and demand, to a full scale day-ahead market that 4

produces hourly prices at over 3,000 different locations, and real-time prices every five minutes. 5

California’s electricity market now closely resembles those run in other areas in the U.S., namely 6

Pennsylvania-New Jersey-Maryland (PJM), New York Independent System Operator (NYISO), New 7

England Independent System Operator (ISO-NE), and the Midwest Independent System Operator (MISO). 8

A. Overview of the Original Market Structure 9

To understand some of the complexity MRTU created, it is beneficial to understand the structure it 10

replaced and the issues with the original market design that MRTU was designed to correct. The following 11

is a description of the structure that existed prior to the implementation of MRTU. 12

1. Zonal Model with Day-Ahead Congestion Management 13

The original model only considered, priced and redispatched for transmission congestion on CAISO 14

interties and the interfaces between three zones within the CAISO (NP15, ZP26, SP15). This frequently 15

resulted in infeasible schedules and commitments, as well as inefficient pricing. Any “intra-zonal” 16

congestion was addressed in real-time, often via out-of-sequence or out-of-market dispatch. 17

2. Balanced Scheduling Requirement 18

While the pre-MRTU structure produced congestion prices, it did not produce organized market day-19

ahead energy prices since there was no competitive day-ahead organized energy market. Rather, market 20

participants were required to balance their own supply and demand via the schedules they submitted daily to 21

the CAISO. This became known as the “balanced schedule” requirement. 22

3. Financial Transmission Rights (FTRs) 23

In conjunction with producing intertie and zonal congestion prices, the CAISO offered, via auction, 24

Financial Transmission Rights (FTRs) to hedge the congestion costs. Notably, in any month there were 25

only about 32 different paths available to the market. 26

4. Day-Ahead and Hour-Ahead Ancillary Service Markets 27

The only true market in the day-ahead time frame was for ancillary services. On an hourly basis, the 1

CAISO procured Spinning Reserve, Non-Spinning Reserve, Regulation Up and Regulation Down. While 2

the day-ahead process typically procured 90% or more of the total needs, the CAISO also procured residual 3

amounts of Ancillary Services in a similar hour-ahead process. 4

5. Zonal Real-Time Energy Market 5

The only energy market run by the CAISO was the real-time energy market. Due to Commission 6

and FERC rules, the real-time market typically represented less than 5% of the CAISO daily energy needs. 7

In effect, it served as a balancing market to fine tune results from the day-ahead scheduling process. While 8

it produced prices every ten minutes, the real-time market, at most, produced two different internal zonal 9

prices if there was congestion. Another major function of the real-time market was to address infeasibilities 10

from the day-ahead market, and to address intra-zonal congestion. 11

6. Reliability Must Run (RMR) Units and Must-Offer Waiver Denial 12

The original market relied on the market to self-commit (i.e. start up and shut down) resources 13

without guidance from the CAISO. However, the CAISO often had reliability needs that required 14

commitments beyond what the market would do based on pure economic decisions. To address these 15

reliability issues, the CAISO relied on manual commitments and dispatches to RMR units and manual 16

commitments via Must-Offer Waiver Denial.1 The Waiver Denial process was instituted by FERC because 17

the CAISO did not have adequate tools to dispatch units needed for reliability. 18

B. Overview of the MRTU Market Structure and Its Impact on SCE’s Business Processes 19

Against the background of the previous structure, the additional complexity of MRTU becomes 20

clearly evident. Various components of MRTU are described below. 21

1. Day-Ahead Energy Market 22

MRTU has a centralized day-ahead energy market. The market produces hourly energy prices at 23

about 1PM the day prior to delivery. MRTU introduced a centralized day-ahead energy market called the 24

Integrated Forward Market (IFM). The IFM requires participants to submit detailed hourly bids for every 25 1 The Waiver Denial process was instituted by FERC after the energy crises of 2000-2001 because the CAISO did not have

adequate tools to dispatch units needed for reliability.

generating unit or intertie location (for imports/exports) subject to a sale. Further, the market requires that 1

all load purchasers submit hourly bids at the location they will purchase power or to submit “self- 2

schedules” where a supplier will produce or a buyer will consume irrespective of price. For the bulk of 3

SCE’s load, the bid is submitted at our Default Load Aggregation Point (DLAP). After the IFM runs, 4

hourly market prices and awards are published. The day-ahead market typically clears over 95% of the total 5

forecasted energy needs for the next day. Billions of dollars worth of transactions clear this market 6

annually. 7

2. Full Network Model (FNM) 8

Whereas the old structure only considered zonal and import transmission constraints, MRTU models 9

the entire transmission system in detail. This Full Network Model (FNM) includes a detailed representation 10

of the entire CAISO transmission system, including electrical characteristics (e.g. transmission capability) 11

and connections for each component (e.g. lines and transformers) of the grid. Market results are calculated 12

based on the FNM to ensure that both zonal and intrazonal congestion is addressed. Moreover, the CAISO 13

includes a host of transmission nomograms that not only ensure lines are not thermally overloaded, but that 14

in the event of certain contingency events, line flows do not exceed reliability limits (these may be lower 15

than thermal limits). 16

3. Locational Marginal Prices (LMP) 17

Because the CAISO now incorporates all of the transmission system into its market, it produces 18

different energy prices at over 3,000 different nodes. This is in dramatic contrast to the one or two internal 19

prices produced under the old system. In the day-ahead market, the prices are produced hourly. In the real-20

time market, the prices are produced every five minutes. This is in dramatic contrast to the one or two 21

internal prices produced under the old system. 22

LMPs include three components, System Marginal Energy Costs, Marginal Congestion Cost, and 23

Marginal Loss Costs. The optimization calculates unique congestion and loss components for every node 24

on the system. The System Marginal Energy cost is identical for all locations. The sum of these three 25

components results in over 3,000 unique nodal prices. As a result, every generator in the grid may have a 26

different clearing price, and every load node may have a different price. The sheer volume of different 27

prices, compared with the prior market that at most produced two different internal prices, has significant 1

impacts on dispatch, operations, bidding and settlements. 2

4. Congestion Revenue Rights Process (CRRs) 3

As noted above, unique congestion prices are calculated for every node. The CAISO provides 4

financial hedging instruments, CRRs, that pay or require the CRR holder to pay the marginal congestion 5

cost between two nodes. While in some ways similar to the old FTR process, CRRs are immensely more 6

complicated and robust. For example, whereas there were only about 32 different FTRs available, CRRs 7

can be configured between any two nodes, making over 12 million different CRRs available for 8

consideration. Moreover, whereas the FTR auction typically took place on an annual basis, the CRR 9

process has in effect three annual allocation processes, an annual auction, 24 monthly allocation processes 10

and 12 monthly auctions. 11

Thus, the products that must be considered, and the auction and allocation processes that must be 12

utilized to award the CRRs, are immensely more complicated than the previous FTR structure. 13

5. Security Constrained Unit Commitment 14

To help ensure feasible schedules as well as a reliable grid, the CAISO not only models all 15

transmission constraints, but the optimization includes many details of the precise operating capability of all 16

generating units. Information includes start-up and shut-down times, minimum run times, minimum down 17

times, ramp rates over various operating ranges, production capability, minimum load levels, and the 18

capability to provide ancillary services via associated ramp rates. With this information, the optimization is 19

able to commit (i.e. start-up and shut-down) units to ensure feasible and reliable operations over a 24-hour 20

optimization horizon. This is in direct contrast to the prior market in which participants were often able to 21

schedule units at will, even if such schedules were physically infeasible. 22

This new complexity requires market participants to provide the CAISO with detailed information, 23

and maintain it, often in or near real-time as units have operational issues or outages that impact availability. 24

6. Simultaneous Cooptimization of Energy, Ancillary Services, Congestion and Losses Over a 25

24-Hour Horizon 26

Given that the MRTU optimization has a detailed model of the transmission system, reliability 1

constraints and the physical capability of all the generation in the grid, CAISO is able to simultaneously 2

optimize energy, ancillary services, congestion and losses in the day-ahead market. The optimization 3

attempts to minimize total costs (as defined in an objective function that has not been fully documented by 4

the CAISO) over a 24-hour horizon. Performing this in a simultaneous manner, as opposed to the clearing 5

energy first, and then sequentially solving for ancillary service needs, will reduce total costs, all else being 6

equal. Collectively, the integration of unit commitment, energy pricing and solving reliability constraints is 7

known as the Integrated Forward Market (IFM). 8

7. Integration of Resource Adequacy and “Must-Offer” Requirements 9

Whereas the pre-MRTU structure relied heavily on the must-offer waiver denial process, MRTU 10

integrates Resource Adequacy (RA) must-offer requirements. RA resources have the obligation to make 11

their capacity available to the day-ahead, and in some cases, the real-time markets. Moreover, MRTU 12

software must track precisely which units and precisely how much of their capacity is RA. This is 13

necessary because MRTU requirements dictate that RA units must offer their RA capacity to the market, 14

and if the market participant fails to do so, CAISO will submit proxy bids for the RA capacity on the 15

participants’ behalf. This results in a reporting burden on market participants, to ensure their RA resource 16

portfolio is accurately represented to the CAISO and that all proxy bid information is maintained and 17

updated. 18

8. Comprehensive Local Market Power Mitigation 19

Unlike the pre-MRTU market which had very limited market power mitigation, MRTU evaluates 20

every location on the grid to determine if market power mitigation is necessary. In effect, any unit that is 21

needed to resolve a local need, rather than a system need, is subject to mitigation. For the initial 22

implementation of MRTU, mitigation relies heavily on cost based information provided to the CAISO 23

through master file updates. If a unit is subject to mitigation, rather than its market based bid, proxy bids 24

calculated with the master file information are used. As a result, participants must ensure that cost and 25

availability information is updated to reflect any changes, or in some cases to reflect changes in gas and 26

emission prices. 27

9. Residual Unit Commitment (RUC) Process 1

In addition to the complexities of the full day-ahead market, the CAISO runs a residual process after 2

the day-ahead market to address any potential reliability issue that may exist based on the difference 3

between load that cleared the market and the CAISO load forecast for the next day. 4

This RUC process requires participation from all RA units, but is voluntary for non-RA units. Non-5

RA units that choose to participate must provide a “RUC Availability” bid and CAISO must pay these non-6

RA units if the optimization commits them. The RUC process also creates locational LMPs and may 7

produce different prices, in every hour, for over 3,000 nodes. 8

10. Hour-Ahead Scheduling Process 9

MRTU also allows hourly transactions on the interties just prior to real-time. The CAISO uses these 10

bids, as well as bids submitted from internal generation along with a load forecast, to set hourly prices for 11

the interties. Unlike the prior market, these hourly prices are financially binding clearing prices, and every 12

participant executing HASP transactions at a given intertie settles at that hourly price. 13

11. Real-Time Energy and Ancillary Service Markets 14

In MRTU,participants are allowed to submit new bids in the real-time market every hour just prior to 15

the start of the operating hour. The CAISO uses these bids, and effectively repeats much of the IFM process 16

in real-time. While MRTU purchases 100% of its forecasted ancillary service needs in the IFM, residual 17

supply needs due to changes in forecast load, or events such as transmission line or unit unavailability, are 18

procured in real-time. Energy prices are generated every five minutes, again for over 3,000 nodes,for 19

energy. Ancillary service prices are produced every 15 minutes for up to 12 different AS zones. 20

C. Conclusion 21

In sum, MRTU not only adds many additional new market features, but carryover features from the 22

old design are now greatly more complex. The ability to reliably operate the system under MRTU requires 23

detailed modeling of not only the entire transmission system, but also of the physical operating 24

characteristics of all the generating units on the grid, and a detailed distribution of the load on the gird. This 25

added complexity, while promising to increase market efficiency, complicates virtually every dimension of 26

the market. The production of multi-component LMPs and over 3,000 nodes results in significant 1

complexities related to CRRs, operations, bidding and settlements. 2

Appendix XVI-A

Appendix to Chapter XVI

Sumner J. Koch Senior Attorney [email protected]

P.O. Box 800 2244 Walnut Grove Ave. Rosemead, California 91770 (626) 302 3253 Fax (626) 302 2050

June 21, 2006

VIA EMAIL & UPS

Mr. Sean Gallagher Director, Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102

Re: R.04-04-003 Mohave Monthly Status Report

Dear Mr. Gallagher:

The Commission’s December 2, 2004, Decision regarding the Mohave Generating Station (Mohave), D.04-12-016, directs Southern California Edison Company (SCE) to “file monthly reports with the Commission’s Energy Division updating any progress made on the [Mohave-related] coal and water negotiations, the C-Aquifer studies, the alternatives investigation and shortening the Gantt Chart time-line.” (D.04-12-016 at Ordering Paragraph 4). SCE hereby submits the 18th such monthly report, which is enclosed.

As discussed in the enclosed report, SCE has just concluded a comprehensive reassessment of the ongoing efforts to return Mohave to operation. Based on this review SCE has reluctantly determined that it cannot continue to pursue resumed operation of the Mohave power plant as an SCE asset. This determination is not based on any single factor but rather on numerous contributing factors, as discussed in the report. SCE is now engaging in discussions with the other three Mohave co-owners regarding the future of Mohave, and with other relevant entities, including the Hopi Tribe and Navajo Nation, about appropriate next steps. The Mohave co-owners have all agreed that a substantial further reduction in Mohave’s staffing level is now appropriate, but the exact staffing level to be maintained has not yet been determined and is expected to be decided in July.

Because of this major development, SCE is providing copies of this monthly report to all

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Commissioners in addition to the other recipients indicated below.

Please do not hesitate to contact me if you have questions regarding this report.

Very truly yours,

Sumner J. Koch

cc: President Michael R. Peevey (assigned Commissioner, R.04-04-003) Commissioner Geoffrey F Brown Commissioner Dian M. Grueneich Commissioner John Bohn Commissioner Rachelle Chong Randy Wu, Esq. ALJ Carol Brown All Parties of Record, A.02-05-046 (as subservice list of R.04-04-003)

SJK:kar:Law#1285517.doc

Enclosure(s)

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SOUTHERN CALIFORNIA EDISON COMPANY MONTHLY MOHAVE STATUS REPORT

PURSUANT TO D.04-12-016

June 21, 2006

This report is submitted by Southern California Edison Company (SCE) to the Energy Division of the California Public Utilities Commission (Commission), pursuant to Commission Decision 04-12-016. Ordering Paragraph 4 of D.04-12-016 directs SCE to file “monthly reports with the Commission’s Energy Division updating any progress made on the coal and water negotiations [related to post-2005 operation of the Mohave Generating Station (Mohave)], the C-Aquifer studies, the alternatives investigation1 and shortening the Gantt Chart time-line.”

This is the 18th monthly report, and covers the period from the week of May 29, 2006, through June 19, 2006.

During this period, SCE completed a comprehensive reassessment of the ongoing efforts to return Mohave to operation and the various factors that still confront resumed operations. Based on this review, SCE has reluctantly determined that it cannot continue to pursue resumed operation of the Mohave power plant as an SCE asset. This determination is not due to any single factor but rather due to numerous contributing factors, each of which are significant singly and which in combination further complicate and exacerbate one another. Among these factors are the following:

� The prospects for cost-effectiveness of Mohave for SCE’s customers, including the greatly decreasing prospects for cost-effectiveness for SCE customers if Mohave cannot be returned to service by 2010.

� The prospects for successfully returning Mohave to service, including the outlook for returning Mohave to operation by 2010, taking into account all factors including:

o Current status of negotiations for coal and slurry water supplies and the time likely required to achieve final binding agreements;

o Current status of the federal Environmental Impact Statement (EIS) for the Black Mesa Project, which includes the contemplated C-Aquifer alternate water supply, the time likely required for issuance of a Final EIS, and prospects for subsequent legal challenges and associated delay;

o Other necessary regulatory approvals, and the associated time requirements;

o The ongoing opposition to use of the C- and N-Aquifers for mine and slurry pipeline uses.

1 There has been no change during this reporting period regarding the Mohave Alternatives/Complements Study (MACS). As mentioned in prior Mohave monthly reports, the final MACS Report was issued by the MACS contractor.

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o The inability to obtain relief from the Consent Decree to allow the plant to operate pending regulatory approvals.

o Potential impacts of possible legal and regulatory developments regarding global climate change and carbon emissions;

o The uncertainty regarding the level of co-owner commitment to pursuing a 2010 return to service, and the decision by the Los Angeles Department of Water and Power that is does not intend to participate in Mohave resumed operation or in further efforts and expenditures to return Mohave to operation.

� The significant expenditures and commitments that would be required over coming months, and would ramp up rapidly over 2007 (for example, for further engineering of the required plant upgrades), in order to preserve a possibility of a 2010 Mohave restart.

SCE and the other Mohave co-owners have now concluded that a substantial further reduction in Mohave’s staffing level is now appropriate, and will be meeting shortly to discuss the scope of work and staffing levels. The exact staffing level that should be maintained has not yet been determined. (Under the reduction in force that has already been announced and initiated, Mohave staffing already is being reduced from over 300 employees to 224 employees, effective as of July 1. That reduction is unaffected and will proceed to completion on July 1.) SCE expects the co-owners’ determination regarding the additional reduction in force to be made by the end of July. Due in part to the advance notice and “bumping” provisions under the SCE-UWUA labor agreement, this further reduction in force will not be completed until approximately November, and it will impact employees at SCE locations besides just Mohave. A possible need for staffing changes like this was contemplated in SCE's 2006 General Rate Case, and a two-way balancing account (the Mohave Balancing Account) was established to address the change from a ratemaking standpoint.

SCE and the other Mohave co-owners also have agreed to jointly explore possible options for Mohave’s future, including the possibility of seeking a buyer for the plant. SCE is now engaging in discussions with the other Mohave co-owners and with other relevant entities, including the Hopi Tribe and Navajo Nation and Peabody Western Coal Company (Peabody), regarding appropriate next steps with regard to Mohave. It is still possible SCE and at least some of the other Mohave co-owners may conclude that it is appropriate to continue pursuing resolution of all remaining coal and water supply issues with the two Tribes and Peabody, and/or to continue funding of the Black Mesa Project EIS, to enhance the marketability of the plant.

CERTIFICATE OF SERVICE

I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I have this day served a true copy of MOHAVE MONTHLY STATUS REPORT on all parties identified

on the attached service list(s). Service was effected by one or more means indicated below:

� Transmitting the copies via e-mail to all parties who have provided an e-mail address. First class mail will be used if electronic service cannot be effectuated.

� Placing the copies in sealed envelopes and causing such envelopes to be delivered by hand or by overnight courier to the offices of the Commission or other addressee(s).

� Placing copies in properly addressed sealed envelopes and depositing such copies in the United States mail with first-class postage prepaid to all parties.

� Directing Prographics to place the copies in properly addressed sealed envelopes and to deposit such envelopes in the United States mail with first-class postage prepaid to all parties.

Executed this 21st day of June, 2006., at Rosemead, California.

______________________________________________Lizette Vidrio

Project Analyst SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

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