PUBL IC VERSION - Southern California Edison...J. Aldri T. Fron K. Bleb P. Ott M. Ben G. Hen J. Rumb...

ApplicatiExhibit NWitnesse

ion No.: No.: es:

A.13-04SCE-02D. CoxM. LanS. WilliT. WatsJ. AldriT. FronK. BlebP. Ott M. BenG. HenJ. Rumb

EnergOf OpChapt

Before the

Public Uti

4-001 2 K

nger J.is Kson Gich Mntino J.bu T

Lnnett J.nry Pble B

gy Resouperationsters IX-X

PUBL

e

ilities Comm

K. Wood . Montanye

K. Koyano G. HuckabyM. Guirguis. Cherrie

T. Walker L. Oliva . Tran

P. Phelan B. Hargreave

(U 338-E

urce Recs, 2012 XVI

LIC VE

mission of th

es

E)

covery A

ERSIO

he State of C

Account

ON

California

Rose

(ERRA)

emead, CalifApril 2,

) Review

fornia2013

w

Energy Resource Recovery Account (ERRA) Review Of Operations, 2012, Chapters IX-XVI

Table Of Contents Section Page Witness

-i-

IX.� PURPA CONTRACT ADMINISTRATION AND COSTS .............................1 D. Cox�

A.� Introduction to PURPA and CHP Contract Administration ..................2�

1.� Summary of PURPA and CHP Contract Activity .....................4�

B.� Contract Management ............................................................................5�

1.� Contract Development ...............................................................5�

2.� Contract Amendment Administration ........................................7�

a)� Carson Cogeneration Company (RAP ID 2087) ............................................................................11�

b)� Lake Shore Mojave (RAP ID 2808) ............................12�

c)� Ridgetop Energy, LLC I and II (RAP ID 6024 and 6092) ............................................................12�

d)� CalWind Resources, Inc. (RAP ID 6365) ....................13�

3.� Contract Assignment Administration ......................................14�

4.� Uncontrollable Force Administration ......................................14�

5.� Forced Outage Claim Administration ......................................16�

6.� Dispute Resolution and Litigation ...........................................20�

a)� Watson Cogeneration Company (RAP ID 2053) ............................................................................20�

b)� CalEnergy (RAP IDs 3004, 3006, 3009, 3025, 3026, 3028 & 3050) ...........................................21�

c)� Ormesa Geothermal I (RAP ID 3104) .........................21�

d)� Dutch Energy (RAP ID 6095)......................................22�

7.� Contribution In Aid of Construction (CIAC) Tax ...................22�

8.� Contract Termination ...............................................................23�


Table Of Contents (Continued) Section Page Witness

-ii-

9.� Collateral Verification .............................................................24�

10.� Other Contract Administration Activities ................................25�

a)� Desert View Power (RAP ID 1038) Application 12-06-017 .................................................25�

b)� Retroactive Payment Calculations for US Borax (RAP ID 2806) and Berry Petroleum (RAP ID 2805) .............................................................26�

C.� Contract Compliance ...........................................................................26 M. Langer�

1.� Capacity Performance Programs ..............................................27�

a)� CapDemo Program.......................................................27�

(1)� CSU Channel Islands Site Authority (RAP ID 2042) .................................................28�

(2)� Salton Sea Power Generation Co #3 (RAP ID 3025) .................................................28�

(3)� Coso Energy Developers (BLM) (RAP ID 3030) .................................................28�

(4)� Ormesa Geothermal 1 (RAP ID 3104) ................................................................28�

(5)� Desert Power (RAP ID 4008) ..........................29�

b)� CapPerformance Program ............................................29�

2.� Metering Energy Deliveries .....................................................30�

a)� PURPA and CHP Projects Within SCE’s Territory .......................................................................31�

(1)� The RTEM Process ..........................................31�

(2)� Interval Meters .................................................32�

(3)� CAISO Meters .................................................32�

b)� Out-of-Service Territory PURPA Projects ..................32�



-iii-

3.� Prescribed Dispatch .................................................................33�

a)� Wheelabrator Norwalk (RAP ID 2064) .......................33�

b)� E.F. Oxnard (RAP ID 2205) ........................................33�

4.� Protection Equipment Testing Program ...................................33�

5.� QF Efficiency Monitoring Program .........................................34�

6.� Scheduled Maintenance ...........................................................35�

7.� Wind Operating Programs .......................................................36�

a)� Turbine Inventory ........................................................36�

b)� Real-time Wind Monitoring System ............................37�

c)� VAR Program ..............................................................37�

d)� Wind Curtailments .......................................................39�

(1)� Supporting Maintenance and Upgrades of the Electrical System ...................39�

(2)� The TRTP Project ............................................40�

(3)� The Goldtown-Lancaster 66 kV Transmission Line ............................................41�

(4)� Automatic Recloser Replacement ....................41�

8.� Insurance Verification ..............................................................41�

9.� Forecasting and Scheduling Accuracy .....................................42�

D.� Affiliate Contract Information .............................................................43�

1.� Watson Cogeneration Company (RAP ID 2053) .....................49�

2.� Sycamore Cogeneration Company (RAP ID 2058) and Kern River Cogeneration Company (RAP ID 2801) ........................................................................................50�

E.� PURPA and CHP Contract Payment Process ......................................51 S. Willis�



-iv-

1.� Performance Bonus ..................................................................51�

2.� OST Projects ............................................................................52�

3.� Line Loss Factor ......................................................................52�

4.� Energy and Capacity Rate Calculations ...................................52�

X.� RENEWABLES PORTFOLIO STANDARD CONTRACT ADMINISTRATION COSTS .........................................................................55 D. Cox�

A.� Introduction to RPS Contract Administration......................................55�

B.� Contract Management ..........................................................................57�

1.� Contract Development .............................................................57�

a)� San Diego Gas & Electric Company Sales Transaction (RAP ID 8009) .........................................63�

b)� Energy America Sales Transaction (RAP ID 8010) ............................................................................64�

2.� Contract Amendment Administration ......................................64�

a)� Solar Partners XX (RAP ID 5214)...............................67�

b)� Recurrent (RAP IDs 5240, 5247, 5249, 5252, and 5493) ...........................................................67�

c)� SPS Corcoran West, LLC (RAP ID 5283)...................69�

d)� Silver State Solar Power South, LLC (RAP ID 5284) .......................................................................69�

e)� Cascade Solar (RAP ID 5351) .....................................69�

f)� Solar Star CA (RAP IDs 5412 and 5413) ....................70�

g)� Garnet Solar Power Generation (RAP ID 5488) ............................................................................71�

h)� Alta Wind VI, LLC (RAP ID 6319) ............................71�

3.� Contract Assignment Administration ......................................72�



-v-

4.� Energy Delivery Performance Administration ........................74�

a)� Ventura Regional Sanitation District (RAP ID 1221) .......................................................................74�

b)� ORNI 18 (North Brawley) (RAP ID 3108)..................74�

5.� Uncontrollable Force Administration ......................................75�

6.� Dispute Resolution and Litigation ...........................................76�

a)� Bonneville Power Administration................................76�

b)� Western Water and Power Production, Limited (RAP ID 1223) ...............................................77�

c)� California Solar 10 (RAP ID 5231) .............................77�

d)� LightSource Renewables (RAP IDs 5237, 5238, and 5239) ...........................................................78�

e)� Sustainable Energy Capital Partners (RAP ID 5253) .......................................................................78�

f)� Silverado (RAP IDs 5463, 5468, 5469, and 5476) ............................................................................79�

g)� Clear Peak Energy, Inc. (RAP ID 5491) ......................80�

h)� Alta Curtailments (RAP IDs 6314 - 6319 and 6321) .....................................................................80�

i)� Sand Canyon (RAP ID 6341) ......................................81�

7.� Contract Termination ...............................................................82�

a)� Imperial Valley Resource Recovery (RAP ID 1209) .......................................................................83�

b)� Solar Partners XVII (RAP ID 5211) ............................84�

c)� ImMODO California (RAP IDs 5593, 5594, 5595, and 5596) ...........................................................85�

8.� RPS Projects That Achieved Commercial Operation ..............85�



-vi-

9.� Collateral ..................................................................................86�

a)� Development Security ..................................................86�

b)� Performance Assurance ...............................................91�

10.� Other Contract Administration Activity ..................................92�

a)� Temescal Canyon RV, LLC (RAP ID 5277) ...............92�

b)� Windstar Energy, LLC (RAP ID 6307) .......................94�

C.� Contract Compliance ...........................................................................94�

1.� Renewable Capacity Verification ............................................94�

2.� Measuring Energy Deliveries ..................................................97�

3.� Active Monitoring ....................................................................97�

4.� Western Renewable Energy Generation Information System (WREGIS) ...................................................................99�

5.� RPS Insurance Verification....................................................100�

XI.� CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO)-RELATED COSTS ........................................................................102 T. Watson�

A.� Background ........................................................................................102�

B.� Grid Management Charges ................................................................102�

C.� Net Market Costs ...............................................................................102�

1.� Ancillary Services Costs ........................................................103�

2.� Imbalance Energy Costs ........................................................103�

3.� Congestion Charges ...............................................................104�

a)� CRR Costs ..................................................................104�

4.� Net Energy Bid Award Charges ............................................105�



-vii-

5.� Residual Unit Commitment (RUC) Capacity Bid Award Revenue ......................................................................105�

D.� SCE Peaker Cost Allocation Mechanism (CAM) Revenues .............105�

E.� FERC Fees .........................................................................................106�

F.� Transmission Loss Charges to Deliver LADWP Returned Energy ................................................................................................106�

G.� Reasonableness of SCE’s CAISO-Related Costs ..............................106�

XII.� OPERATION OF RATEMAKING ACCOUNTS ........................................108 D. Snow�

A.� Introduction ........................................................................................108�

B.� Operation of Balancing Accounts and Adjustment Mechanisms During the Record Period .............................................111�

1.� Operation of the ERRA Balancing Account ..........................111�

a)� Commission-Authorized Transfers ............................112�

b)� Significant Adjustments .............................................112�

c)� Costs ...........................................................................113�

2.� Operation of the BRRBA .......................................................113 J. Aldrich�

a)� Commission Authorized Transfers ............................116�


3.� Operation of the NDAM ........................................................123�



4.� Operation of the PPPAM .......................................................125�





-viii-

5.� Operation of the CBA ............................................................127�



6.� NSGBA ..................................................................................128 T. Frontino�

a)� Introduction ................................................................128�

b)� Background ................................................................128�

c)� Operation of the NSGBA ...........................................130 K. Blebu�

d)� Expenses ....................................................................130 T. Frontino�

7.� Conclusion .............................................................................131�

C.� Review and Disposition of Balancing and Memorandum Accounts Pursuant to Decisions 06-05-016, 09-03-025, and 12-11-051 ...........................................................................................131 P. Ott�

1.� MPBA ....................................................................................131�

a)� Introduction ................................................................131�

b)� Background ................................................................131�

c)� Operation of the MPBA .............................................132�

d)� Description of Medical Program Expenses ................134 M. Bennett�

e)� Conclusion .................................................................138 P. Ott�

2.� PCBA and PBOP BA .............................................................138 K. Blebu�

a)� Introduction ................................................................138�

b)� Background and Ratemaking .....................................139�

c)� Operation of the PCBA and PBOP BA......................140�

d)� Summary Description of Pension Expenses ..............142 G. Henry�

e)� Summary Description of PBOP Expenses .................143�



-ix-

f)� Conclusion .................................................................144 K. Blebu�

3.� RSMA ....................................................................................144�

a)� Introduction ................................................................144�

b)� Background ................................................................144�

c)� Operation of the RSMA .............................................145�

d)� Conclusion .................................................................146�

D.� Review and Disposition of Other Miscellaneous Account Balances .............................................................................................146 J. Rumble�

1.� FCPMA ..................................................................................146�

a)� Introduction ................................................................146�

b)� Background and Ratemaking .....................................147�

c)� Operation of the FCPMA ...........................................147 K. Blebu�

d)� FCPMA Recorded Expenses - Details .......................148�

e)� Conclusion .................................................................148�

E.� Review of Miscellaneous Account Balances for Recovery ...............149 P. Ott�

1.� PDDMA .................................................................................149�

a)� Introduction ................................................................149�

b)� Background ................................................................149�

c)� Operation of the PDDMA ..........................................150�

d)� Preliminary Statement Modification ..........................151�

e)� PDD Recorded Expenses – Details ............................151 J. Rumble�

(1)� Outside Services.............................................152�

(2)� Miscellaneous Expenses ................................152�



-x-

(3)� Labor ..............................................................152�

(4)� Generation Planning & Strategy Support (GP&S) .............................................153�

(5)� Labor and Expense Chargebacks ...................153�

(6)� Membership/Dues ..........................................153�

(7)� Conclusion .....................................................153�

2.� PAACBA ...............................................................................154 K. Wood�

a)� Introduction ................................................................154�

b)� Background ................................................................154�

c)� Operation of the PAACBA ........................................155 P. Ott�

d)� Recorded Expenses for Programs Authorized in 2008-2012 ...........................................156 K. Wood�

e)� Disposition of the December 31, 2012 Balance in the PAACBA ...........................................157�

F.� ESMA and LCTA ..............................................................................157 J. Montanye�

1.� Introduction ............................................................................157�

2.� ESMA and LCTA Overview .................................................157�

a)� Background and Settlement Results ..........................157�

b)� October 2001 Settlement Agreement and Advice Letter 1811-E .................................................158�

c)� Resolution E-3894 and Subsequent Commission Approvals ..............................................158�

d)� SCE’s Offer to Forego the Shareholder Incentive .....................................................................159�

3.� Operation of the ESMA .........................................................160�

4.� ESMA Transfer to the ERRA ................................................162�



-xi-

a)� 2013 ERRA Forecast Application .............................162�

5.� Operation of the LCTA ..........................................................162�

6.� Reasonableness of Litigation Costs .......................................163 K. Koyano�

7.� Recovery of Amounts Recorded in the LCTA ......................166 J. Montanye�

8.� Conclusion and Request for Finding......................................166�

XIII.� EDISON SMART CONNECT PROGRAM COSTS RECOVERY .............168 K. Blebu�

A.� Background and Ratemaking .............................................................168�

B.� Operation of the ESCBA ...................................................................169�

C.� Edison SmartConnect Operational Benefits .......................................170 G. Huckaby�

D.� Edison SmartConnect Capital Benefits ..............................................171 K. Blebu�

E.� Description of Phase III Costs ...........................................................171 M. Guirguis�

1.� Acquisition of Meters and Communication Network Equipment ..............................................................................173 J. Cherrie�

2.� Installation of Meters and Communication Network Equipment ..............................................................................173�

3.� Implementation and Operation of New Back Office Systems ..................................................................................173 T. Walker�

4.� Customer Tariffs, Programs, and Services ............................174 L. Olivia�

5.� Customer Service Operations ................................................175 T. Walker�

6.� Overall Program Management ...............................................175 M. Guirguis�

7.� Unrealized Benefits - Program Contingency .........................175 G. Huckaby�

F.� Conclusion .........................................................................................176 K. Blebu�

XIV.� MARKET REDESIGN AND TECHNOLOGY UPGRADE MEMORANDUM ACCOUNT .....................................................................177 J. Tran�

A.� The CAISO’s Market Redesign and Technology Upgrade ...............177�



-xii-

1.� Introduction ............................................................................177�

2.� Summary of Request ..............................................................177�

3.� SCE’s Expenses Are Incremental and Verifiable ..................179�

B.� Capital Costs ......................................................................................180�

1.� Introduction ............................................................................180�

2.� Winter 2011 Release ..............................................................180�

a)� Summary of Costs ......................................................180�

b)� Resources ...................................................................181�

c)� Scope of Work ...........................................................181�

(1)� GMC Rate Structure ......................................181�

(2)� Generated Bids and Outage Reporting for Non-Resource Specific Resource Adequacy (NRS-RA) Resources .......................................................182�

(3)� Multi-Stage Generator (MSG) Phase 1......................................................................182�

(4)� Flexible Ramping Constraint .........................182�

(5)� Grouping Constraints .....................................182�

3.� Spring 2012 Release ..............................................................182�


b)� Resources ...................................................................183�

c)� Scope of Work ...........................................................183�

(1)� Multi-Stage Generator (MSG) Phase 2......................................................................184�



-xiii-

(2)� Non-Generating Resource/Regulation Energy Management Phase 1 .....................................184�

(3)� Local Market Power Mitigation Enhancements Phase 1 ...................................184�

(4)� Default O&M Adder ......................................184�

(5)� Enhancements to Virtual Bidding Software .........................................................184�

4.� Infrastructure Expansion ........................................................185�


b)� Resources ...................................................................185�

c)� Scope of Work ...........................................................186�

C.� O&M Costs ........................................................................................186�

1.� Introduction ............................................................................186�

2.� IT Maintenance Costs ............................................................186�

a)� License Renewal ........................................................187�

b)� Labor Costs ................................................................188�

(1)� Software Maintenance Costs..........................189�

(2)� Server Hardware Maintenance .......................191�

D.� Summary of Entries Recorded in the MRTUMA ..............................192 D. Snow�

E.� Conclusion .........................................................................................193�

XV.� MOHAVE BALANCING ACCOUNT .........................................................194 K. Blebu�

A.� Introduction ........................................................................................194�

B.� Background and Ratemaking .............................................................194�

C.� Operation of the MBA .......................................................................195�



-xiv-

D.� Mohave Capital-Related Revenue Requirement ................................196�

E.� Operating Expenses ...........................................................................197 P. Phelan�

1.� O&M Costs ............................................................................197�

a)� Background ................................................................197�

b)� 2012 Record Period Expenses ...................................198�

2.� A&G, Payroll Taxes, and A&G Participant Credits ..............198 K. Blebu�

3.� Worker Protection Expenses ..................................................199�

F.� Plant Decommissioning Status ..........................................................199 P. Phelan�

G.� Conclusion .........................................................................................200 K. Blebu�

XVI.� AUDITS .........................................................................................................202 B. Hargreaves�

A.� SONGS Inventory Warehouse Processes and Practices (Store Location 0907 and newly created Store 0060) (Y11-52013) ................................................................................................202�

B.� San Onofre Nuclear Generating Station (SONGS) – Environmental Preliminary Assessment (Y11-52015) ......................203�

C.� SONGS’ Contingent Worker Timekeeping Process Review (Y12-11102) .......................................................................................203�

D.� SONGS Workplace Safety Inspection Process (Y12-52003) ............203�

E.� SONGS NRC Cyber Security Project Review (Y12-74004) .............204�

F.� Catalina Plant - (Y11-53003) .............................................................204�

G.� Outage Management - (Y11-76010) ..................................................204�

H.� SONGS Aboveground Storage Tanks (Y12-52002)..........................205�

I.� Operational & Environmental, Health and Safety Assessment - Mountainview (Y12-52011) ........................................205�

J.� Outage Management Process – Planned Outages (Y12-58009) ................................................................................................205�


List Of Tables Table Page

-xv-

Table IX-1 PURPA New Contracts January 1, 2012 Through December 31, 2012 ...................................6�

Table IX-2 CHP New Contracts January 1, 2012 Through December 31, 2012 ........................................7�

Table IX-3 PURPA and CHP Contract Amendments and Agreements January 1, 2012

Through December 31, 2012 .................................................................................................................9�

Table IX-4 PURPA Contract Consents and Consents to Assignments January 1, 2012

Through December 31, 2012 ...............................................................................................................14�

Table IX-5 PURPA Uncontrollable Force Claims Tendered and/or Pending January 1,

2012 Through December 31, 2012 ......................................................................................................16�

Table IX-6 PURPA Forced Outage Claims January 1, 2012 Through December 31, 2012 .....................18�

Table IX-7 PURPA Contract Terminations January 1, 2012 Through December 31, 2012 .....................24�

Table IX-8 CapPerformance Failures January 1, 2012 Through December 31, 2012 ..............................30�

Table IX-9 Projects That Failed to Submit Operating and Efficiency Data for Calendar

Year 2011 .............................................................................................................................................35�

Table IX-10 PURPA Non-Compliant VAR Projects January 1, 2012 Through December

31, 2012................................................................................................................................................39�

Table IX-11 Affiliate PURPA / CHP Projects and Ownership January 1, 2012 Through

December 31, 2012 ..............................................................................................................................44�

Table IX-12 Summary of Production by and Payments to Affiliate PURPA Projects

January 1, 2012 Through December 31, 2012. ....................................................................................44�

Table IX-13(a) Production by and Payments to Affiliate PURPA Projects January 1, 2012

Through December 31, Project Name: Watson Cogeneration Company (RAP ID

2053) ....................................................................................................................................................45�

Table IX-14 Allowed Affiliate Maintenance Hours January 1, 2012 Through December

31, 2012................................................................................................................................................48�


List Of Tables (Continued) Table Page

-xvi-

Table X-15 RPS New Contracts Executed January 1, 2012 Through December 31, 2012 .......................58�

Table X-16 RPS Contract Amendments January 1, 2012 Through December 31, 2012 ..........................65�

Table X-17 .................................................................................................................................................68�

Table X-18 RPS Contract Assignments January 1, 2012 Through December 31, 2012 ...........................73�

Table X-19 RPS Uncontrollable Force Claims Tendered and/or Pending January 1, 2012


Table X-20 RPS Contract Terminations January 1, 2012 Through December 31, 2012 ..........................82�

Table X-21 RPS Contracts that Achieved Commercial Operation January 1, 2012


Table X-22 RPS Contract Development Security January 1, 2012 Through December 31,

2012......................................................................................................................................................87�

Table X-23 RPS Contract Performance Assurance January 1, 2012 Through December

31, 2012................................................................................................................................................92�

Table X-24 .................................................................................................................................................94�

Table X-25 Renewable Capacity Verifications January 1, 2012 Through December 31,

2012......................................................................................................................................................96�

Table X-26 RPS Active Monitoring January 1, 2012 Through December 31, 2012 .................................99�

Table XI-27 Total CAISO-Related Costs Incurred by SCE During the Record Period

(Million Dollars) ................................................................................................................................107�

Table XII-28 Summary of 2014 Revenue Requirement Change ($000) .................................................109�

Table XII-29 .............................................................................................................................................110�

Table XII-30 Operation of the ERRA ......................................................................................................111�

Table XII-31 Operation of the BRRBA ...................................................................................................115�

Table XII-32 Operation of the NDAM ....................................................................................................124�



-xvii-

Table XII-33 Operation of the PPPAM ...................................................................................................126�

Table XII-34 Operation of the CBA ........................................................................................................127�

Table XII-35 Operation of the NSGBA ...................................................................................................130�

Table XII-36 Operation of the MPBA .....................................................................................................133�

Table XII-37 SCE’s Pension Assets and Obligations ($Millions) ...........................................................141�

Table XII-38 Operation of the PCBA ......................................................................................................142�

Table XII-39 Operation of the PBOP BA ................................................................................................143�

Table XII-40 Operation of the RSMA .....................................................................................................146�

Table XII-41 Operation of the FCPMA ...................................................................................................148�

Table XII-42 Operation of the PDDMA ..................................................................................................151�

Table XII-43 PDDMA 2012 Expenses by Category ...............................................................................152�

Table XII-44 Annualized AMP Contract Administrative Authorized Funding and Actual

Costs For the Period 2008 through 2012 ($000) ................................................................................155�

Table XII-45 Purchase Agreement Administrative Costs Balancing Account Summary

For the Period 2008 through 2012 ($000)..........................................................................................156�

Table XII-46 Annualized PAACBA Actual Costs by Labor and Non-Labor For the

Period 2008 through 2012 ($000) ......................................................................................................157�

Table XII-47 Operation of the ESMA .....................................................................................................160�

Table XII-48 .............................................................................................................................................161�

Table XII-49 Operation of the LCTA ......................................................................................................163�

Table XIII-50 Edison SmartConnect Balancing Account .......................................................................170�

Table XIII-51 Edison SmartConnect Phase III 2012 Expenditures ($000) .............................................172�

Table XIV-52 Summary of MRTU Expense Request .............................................................................178�

Table XIV-53 Summary of MRTU Direct Capital Request ....................................................................179�



-xviii-

Table XIV-54 Summary of Total Capital Costs ($Millions) ...................................................................180�

Table XIV-55 Summary of Winter Release-Related Costs ($Millions) ..................................................180�

Table XIV-56 Summary of Spring Release-Related Costs ($Millions) ..................................................183�

Table XIV-57 Summary of Infrastructure Expansion Costs ($Millions) ................................................185�

Table XIV-58 Summary of O&M Costs ($Millions) ..............................................................................186�

Table XIV-59 MRTU Software License Renewal Costs .........................................................................187�

Table XIV-60 Market Redesign and Technology Upgrade Memorandum Account

(MRTUMA) .......................................................................................................................................192�

Table XV-61 Mohave Balancing Account 2012 .....................................................................................196�

-1-

IX. 1

PURPA CONTRACT ADMINISTRATION AND COSTS 2

SCE administers power purchase agreements (PPAs) entered into pursuant to the Commission’s 3

implementation of the Public Utility Regulatory Policies Act of 1978 (PURPA).1 The counterparties to 4

these PPAs are generally referred to as qualifying facilities (QFs) within the meaning of PURPA, and 5

consist of either small power producers that use renewable resources, or cogenerators as defined in 6

PURPA. Most of these PPAs are “standard offer” contracts approved by the Commission, including: 7

Standard Offer 1 (SO1); Standard Offer 2 (SO2); Standard Offer 3 (SO3); and Interim Standard Offer 4 8

(ISO4) contracts. In addition, SCE has entered into “nonstandard” or negotiated (NEG) contracts with 9

QFs, usually based on a standard offer, which have been approved by the Commission. SCE has also 10

developed a modified version of the SO1 contract, referred to herein as a “reformed” SO1 (RSO1) 11

contract. Finally, SCE entered into extension (EXT) agreements with QFs whose contracts expired prior 12

to a new standard QF contract being available per the Settlement described below. The Commission has 13

directed that these projects may elect to extend the non-price terms and conditions of the expiring 14

contract and continue service with the pricing set forth in the Commission’s decision until a final 15

contract is available.2 16

Since November 2011, SCE has also offered and now administers PPAs entered into pursuant to 17

the Combined Heat and Power (CHP) Program Settlement Agreement (“CHP Settlement”, “QF 18

Settlement”, or “Settlement”), adopted by the Commission in Decision (D.) 10-12-035. This Settlement 19

develops a State CHP Program with the intent to transition from the prior PURPA program for CHP 20

projects above 20 MW to a market-based state-administered program. This program is governed by a set 21

of provisions referred to here as the CHP Settlement Term Sheet (Term Sheet). One of the conditions 22

precedent occurring prior to implementation of the Settlement was that the Federal Energy Regulatory 23

Commission (FERC) had to terminate the PURPA must-take obligation pursuant to Section 210(m) of 24 1 Public Law No. 95-617 (Nov. 9, 1978), 92 Stat. 3117.

2 See D. 07-09-040 at p. 126.

-2-

PURPA, as modified by the Energy Policy Act of 2005,3 for QFs above 20 MW. On June 16, 2011, 1

FERC granted the California Investor Owned Utilities’ (IOUs’)4 application to terminate the PURPA 2

must-take obligation for QFs above 20 MW.5 3

While the Settlement focused on providing a path for CHP above 20 MW to obtain PPAs in the 4

absence of the PURPA must-take obligation, it also established a QF Standard Offer Contract (QF SOC) 5

for QFs 20 MW or less. The QF SOC is a PURPA contract established by the Commission pursuant to 6

its authority to implement PURPA for QFs 20 MW and under. Additionally, the Settlement created two 7

main market-based agreements for CHP projects. The first is the Transition PPA, which is available to 8

all QF CHP units with an existing contract with SCE as of November 23, 2011 (Settlement Effective 9

Date). These contracts are required to expire by June 30, 2015. The second agreement is a Standard 10

PPA signed pursuant to the CHP Settlement’s Request for Offer (RFO) process (CHP RFO PPA). 11

These contracts are not PURPA contracts. In addition to these PPAs, SCE also offers contracts to 12

qualifying CHP projects of 20 MW or less pursuant to AB 1613; like the QF SOC, this program and its 13

associated contracts is administered per the requirements of PURPA, which remains in effect in 14

California for QFs of 20 MW or less.6 15

A. Introduction to PURPA and CHP Contract Administration 16

This chapter discusses SCE’s administration of SO1, SO2, SO3, ISO4, RSO1, EXTs, NEGs, QF 17

SOC, and AB 1613 Agreements; these PPAs are referred to in this chapter as “PURPA contracts,” and 18

the projects that generate power for sale to SCE under such contracts are referred to as “PURPA 19

projects.” This chapter also discusses the administration of Transition PPAs and CHP RFO PPAs; these 20

PPAs are referred to as “CHP contracts,” and the projects that generate power for sale to SCE under 21

such contracts are referred to as “CHP projects.” As explained below, the Commission has authorized 22

3 Public Law No. 109-58 (Aug. 8, 2005), 119 Stat. 594. 4 California Investor-Owned Utilities include SCE, Pacific Gas & Electric, and San Diego Gas & Electric. 5 135 FERC ¶61,234. 6 Adopted in D.09-12-042.

-3-

SCE to recover the costs associated with PURPA and CHP contracts, subject to its review of SCE’s 1

administration of the contracts. 7 2

In D. 97-11-074, the Commission held that “costs associated with QF and interutility contracts 3

should undergo reasonableness reviews” and that “[a]nnual reviews will include a review of contract 4

administration and litigation costs.”8 In addressing the reasonableness of PURPA contract 5

administration, the Commission found that utilities must administer their contracts in a prudent manner, 6

ensuring compliance with the terms and conditions of the contracts and purchasing and selling power in 7

a manner that minimizes customer costs. Utilities are to exercise good utility practice in administering 8

contracts. In other words, utilities are expected to engage in those practices, methods, and acts that, in 9

the exercise of reasonable judgment in light of the facts known at the time the decision was made, could 10

have been expected to accomplish the desired result at a reasonable cost consistent with good business 11

practices, reliability, safety, and expedition. The prudence standard is intended to include a range of 12

acceptable practices, methods, or acts.9 13

In D.02-10-062, the Commission established the ERRA to track utility retained generation, 14

procurement activities, and purchased power expenses. Furthermore, in the Term Sheet of the QF 15

Settlement adopted by D. 10-12-035, the IOUs are directed to “recover the cost of all payments made 16

pursuant to PPAs and PPA Amendments executed under [the] CHP Program in their respective Energy 17

Resources Recovery Accounts”.10 18

In this chapter, SCE sets forth its recorded PURPA and CHP contract-related expenses and 19

describes its PURPA and CHP contract administration activities, demonstrating that it reasonably 20

administered these contracts during the Record Period.11 21

7 PURPA: Public Utilities Code § 367(2); D.95-12-063 at p. 130. CHP: D.10-12-035, approving Section 13.2 of Term

Sheet 8 D.97-11-074 at pp. 125, 127-128. 9 See, e.g., D.90-09-088 at pp. 14-16. 10 CHP Program Settlement Agreement Term Sheet, October 8, 2010, Section 13.2.1 at p. 56 11 Two summary documents accompany this chapter as appendices. Appendix A, titled “List of PURPA and CHP

Projects,” lists each active PURPA and CHP project and the Commission decision that found the applicable PURPA or (Continued)

-4-

1. Summary of PURPA and CHP Contract Activity 1

During the Record Period, SCE purchased 15.821 billion kWh12 from 153 active PURPA 2

projects, and recorded PURPA contract-related costs of $1.002 billion. There were an additional 16 3

PURPA projects on-line that did not sell any power to SCE during the Record Period. Also during the 4

Record Period, SCE purchased 516.1 million kWh13 from 5 active CHP projects, and recorded CHP 5

contract-related costs of $23.8 million. 6

There was 3,580 MW of net on-line capacity available for sale to SCE from PURPA projects 7

during 2012 (i.e., generating capacity net of station use and other committed on-site loads). This net on-8

line capacity includes six different technologies: (1) biomass; (2) cogeneration; (3) geothermal; (4) small 9

hydro; (5) solar; and (6) wind.14 Approximately 58% of SCE’s net on-line capacity from PURPA 10

projects are from renewable technologies15 (2,085 net MW), while the remaining 42% are from 11

cogeneration projects (1,495 net MW).16 In 2012, SCE has contracted with 127 MW of net on-line 12

Continued from the previous page CHP contract reasonable and eligible for rate recovery, subject to the contract administration review described above. Appendix B, titled “ERRA PURPA and CHP Payments Summary Table,” sets forth payment and production figures for each active PURPA or CHP project from which SCE purchased power during the Record Period. The same information for SCE’s affiliated PURPA and CHP projects is also contained in Section D of this chapter.

12 Purchases in billion kWh from PURPA projects by month were as follows:

Billion kWh Delivered Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec. Total 1/01/2012 – 12/31/2012 15.821

13 Purchases in billion kWh from CHP projects by month were as follows:

Million kWh Delivered Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec. Total 1/01/2012 – 12/31/2012 516.1

14 SCE uses a numbering convention called “RAP ID” (Renewable and Alternative Power Identification) to identify

contracts by technology. The 1000 series refers to biomass, the 2000 series refers to cogeneration, the 3000 series refers to geothermal, the 4000 series refers to small hydro, the 5000 series to solar, and the 6000 series to wind. In previous years, these were identified as “QFID” (Qualifying Facilities Identification).

15 Renewable technologies include: small hydro projects less than 30 MW, biomass, geothermal, wind, and solar. Though classified as Qualifying Facilities, output from these RPS-eligible projects contribute to RPS goals.

16 Note that much of this capacity is due to projects that are currently delivering under Legacy PURPA contracts; however, many of these projects have signed and will begin deliveries under non-PURPA Transition PPAs or CHP RFO PPAs in upcoming Record Periods.

-5-

capacity from non-PURPA CHP projects. While most CHP and PURPA projects are situated within 1

SCE’s 50,000 square mile service area, SCE also has PURPA and CHP contracts with projects located 2

in the service areas of Pacific Gas & Electric Company (PG&E), Imperial Irrigation District (IID), and 3

the State of Nevada. 4

The PURPA and CHP contracts administered by SCE during the Record Period include: 22 SO1 5

contracts; 7 RSO1 contracts; 7 SO2 contracts; 15 SO3 contracts; 86 ISO4 contracts; 32 NEG (negotiated 6

contracts), 10 Transition PPAs and 6 CHP RFO PPAs.17 7

B. Contract Management 8

This section provides information on PURPA and CHP contract management, including contract 9

development, amendments, assignments, uncontrollable force claim administration, forced outage claim 10

administration, dispute resolution, contribution in aid of construction (CIAC) tax liability, and contract 11

terminations. SCE pursues these activities and programs in accordance with its contract administration 12

principles and practices, as well as Commission guidelines. The following four fundamental principles 13

have evolved to guide SCE’s administration of its PURPA and CHP contracts: 14

� SCE’s actions must be consistent with Commission directives. 15

� PURPA and CHP contract provisions that benefit or protect SCE’s customers must be enforced 16

pursuant to a reasonable interpretation of contract language. 17

� Contracts with affiliate and non-affiliate PURPA or CHP counterparties are to be administered in 18

a consistent manner. 19

� Where appropriate, SCE’s administration of PURPA and CHP contracts should be consistent 20

with utility and / or industry practice. 21

1. Contract Development 22

During the Record Period, SCE entered into 6 new PURPA and 16 new CHP contracts, 23

identified in Table IX-1 and Table IX-2, respectively. 24

17 These totals include projects operating under an extension agreement.

-6-

Table IX-1 PURPA New Contracts

January 1, 2012 Through December 31, 2012

RAP ID

Project Contract Type Contract Capacity

(MW)

Date Executed CPUC Resolution or Decision

2807 Searles Valley Minerals Inc. QF SOC 4 May 31, 2012 D. 10-12-035

2817 Houweling Nurseries Oxnard, Inc. CHP AB 1613

2 October 25, 2012

D. 09-12-042 (as modified by D. 10-04-055, D. 10-12-055 and D. 11-04-033)

2823 Rhodia, Inc. QF SOC 5 December 10, 2002 D. 10-12-035

5513 Sierra Suntower QF SOC 4.2 May 31, 2012 D. 10-12-035

6365 Calwind Resources, Incorporated QF SOC 9 May 31, 2012 D. 10-12-035

6366 Mogul Energy Partnership I, LLC QF SOC 4 June 22, 2012 D. 10-12-035

-7-

Table IX-2 CHP New Contracts


Note (a): Though these contracts were procured through SCE’s CHP RFO, they are managed in SCE’s Energy Supply and Management group and thus are not assigned RAP IDs

2. Contract Amendment Administration 1

SCE entered into 89 PURPA and CHP contract amendments during the Record Period. Many of 2

these amendments are Legacy Amendments offered per the Settlement. These Pro Forma Legacy 3

Amendments were offered to all QFs that had existing contracts (Legacy PPAs or Legacy Agreements) 4

RAP ID

Project Contract Type

Contract Capacity

(MW)

Date Executed

Term Start Date

CPUC Resolution or

Decision

2814 Berry Petroleum CHP RFO PPA

36 July 2, 2012 July 1, 2014 E-4553

2815 Sycamore Cogeneration Company (Baseload)

CHP RFO PPA

153 July 2, 2012 January 1, 2014 TBD

2816 Sycamore Cogeneration Company (Toll/RA)

CHP RFO PPA

148 July 2, 2012 January 1, 2014

TBD

NA (a)

Harbor Cogeneration Company

CHP RFO PPA

80 July 2, 2012

January 1, 2014 TBD

NA (a)

Los Medanos Energy Center, LLC

CHP RFO PPA

280.5 July 2, 2012

January 1, 2014 Draft Res. E-4569 (SCE AL 2771-E) Pending Approval

NA (a)

Calpine Gilroy Cogen, L.P.

CHP RFO PPA

120 July 2, 2012

January 1, 2014 Draft Res. E-4569 (SCE AL 2771-E) Pending Approval

2805 Berry Petroleum Transition PPA 36 May 31, 2012

June 1, 2012 D. 10-12-035

2806 U.S. Borax Transition PPA 45 May 31, 2012

June 1, 2012 D. 10-12-035

2808 Lake Shore Mojave, LLC

Transition PPA 55 May 31, 2012

June 1, 2012 D. 10-12-035

2809 Watson Cogeneration Company

Transition PPA 282/277 May 31, 2012 TBD E-4537

2810 Sycamore Cogeneration Company

Transition PPA 152 October 15,

2012 TBD TBD

2811 Kern River Cogeneration Company


2012 TBD TBD

2812 City of Palm Springs – Municipal

Transition PPA 0.38 August 1, 2012

August 1, 2012 D. 10-12-035

2813 City of Palm Springs – Sunrise

Transition PPA 0.216 August 1, 2012

August 1, 2012 D. 10-12-035

2820 Sycamore Cogeneration Company (Toll/RA)


2012 TBD TBD

2821 Kern River Cogeneration Company (Toll/RA)


2012 TBD TBD

-8-

with SCE as of the Settlement Effective Date; these projects are often referred to as Legacy QFs. The 1

Legacy Agreements provided five options, called A, B, C1, C2, and C3. Most of these options provide a 2

structure for calculating delivered energy payments; however, option C1 can be selected in conjunction 3

with any of the other options and provides a structure under which SCE and the QF would enter future 4

negotiations for a tolling agreement. The details on these options are explained further in this table: 5

All amendments maintain the existing Legacy PPA term and do not affect capacity prices from 6

the original Legacy PPAs. Among SCE’s Legacy QF portfolio, 76 projects signed Legacy Amendments: 7

12 projects selected Option A, 63 selected Option B, and one selected Option C3. Additionally, one 8

project (discussed in Section B(2)a below) signing an Option A amendment concurrently selected 9

Option C1. Table IX-3summarizes all PURPA and CHP amendments entered into during the Record 10

Period. 11

Legacy Amendment

Option

A B C1 C2 C3

Eligible Contracts

Legacy Legacy Legacy Legacy Legacy

Incremental Energy Heat Rate (IER)

2012 = 8,225 2013 = 8,125 2014 = 8,125 2015 = 2011 & 2012 Actual Heat Rate 2016+= Market

2012 = 8,600 IER

2013 = 8,500 IER 2014 = 8,500 IER 2015+= Market

Negotiated bilateral tolling

agreement replaces

existing QF legacy

contract

2012 = 8,335 IER 2013 = 8,235 IER 2014 = 8,235 IER 2015+ = Market

2012 = 8,335 IER

2013 = 8,235 IER 2014 = 8,235 IER 2015+ = Market

GHG Risk

Buyer 100% 2013-2015 Seller Negotiated Buyer up to a fixed

$20/tonne and one tonne/MWh

(caps buyer’s $/MWh)

Buyer up to a fixed $12.5/tonne and

historical tonnes of emissions – based on the avg. of 2008/2009

data (caps buyer’s total $)

Location Adjustment Factor

Yes No No Yes Yes

-9-

Table IX-3 PURPA and CHP Contract Amendments and Agreements18

January 1, 2012 Through December 31, 2012 RAP ID

Project Amendment or Agreement and Description Date Executed

1009 LA Co. Sanitation Distribution CSD 2610 Legacy Amendment - Option B (Amendment No. 1) May 24, 2012

1038 Desert View Power, Inc Letter Agreement to allow DVP to market project to third parties January 9, 2012

1038 Desert View Power, Inc Letter Agreement to suspend DVP obligations effective May 1, 2012 April 6, 2012

1038 Desert View Power, Inc SCE to suspend its purchase of the Facility’s output for 10 years, starting May 1, 2012 (Amendment No. 2). See Application 12-06-017 and D. 12-11-035.

May 1, 2012

1077 LA Co. Sanitation Distribution Spadra Legacy Amendment - Option B May 25, 2012

2045 TIN Inc. dba Temple Inland Legacy Amendment - Option A June 1, 2012

2050 Ripon Cogeneration Inc. Legacy Amendment - Option A (Amendment No. 4) April 30, 2012

2055 International Paper Legacy Amendment – Option A (Amendment No. 5) May 24, 2012

2071 ACE Cogeneration Company Legacy Amendment - Option C3 May 21, 2012

2081 Corona Energy Partners, Ltd. Legacy Amendment - Option A (Amendment No. 6) May 29, 2012

2087 Carson Cogeneration Company Legacy Amendment - Option A, Option C1 May 25, 2012

2087 Carson Cogeneration Company Extends the number of calendar days from 90 to 365 to negotiate tolling arrangement under Legacy Amendment Option C1 (Amendment No. 9)

February 14, 2013

2087 Carson Cogeneration Company Amended & Restated PPA to convert baseload cogeneration facility to dispatchable toll in accordance with CHP Settlement Legacy Amendment Option C1.

March 13, 2013

2155 Chevron USA Legacy Amendment - Option A May 21, 2012

2205 E. F. Oxnard Incorporated Legacy Amendment - Option A June 1, 2012

2808 Lake Shore Mojave LLC November 26, 2012

2815 Sycamore Cogeneration Amendment to allow time for both SCE and Sycamore to file for approval at the CPUC and FERC August 30, 2012

2816 Sycamore Cogeneration Amendment to (i) allow time for both SCE and Sycamore to file for approval at the CPUC and FERC and (ii) correct an error in certain variables used to calculate collateral

August 30, 2012

3001 Heber Geothermal Company Legacy Amendment - Option A (Amendment No. 4) June 1, 2012

3003 Mammoth Pacific L.P. (MP1) Legacy Amendment - Option B (Amendment No. 2) June 1, 2012

3004 Del Ranch, LTD., (Niland #2) Legacy Amendment - Option B June 1, 2012

3006 Vulcan/Bn Geothermal Legacy Amendment - Option B June 1, 2012

3009 Elmore Ltd. Legacy Amendment - Option B June 1, 2012

3011 Terra-Gen Dixie Valley, LLC Legacy Amendment - Option B (Amendment No. 4) May 1, 2012

3018 Mammoth Pacific L.P. (PLES) Legacy Amendment - Option B (Amendment No. 3) June 1, 2012

18 Amendments are for the term of the contract. Agreements are for a term shorter than the term of the contract.

-10-

3021 Second Imperial Geothermal Co. Legacy Amendment - Option A (Amendment No. 4) June 1, 2012

3025 Salton Sea Power Generation L.P. #3 Legacy Amendment - Option B June 1, 2012

3026 Leathers L. P. Legacy Amendment - Option B June 1, 2012

3027 Mammoth Pacific L.P. II (MP2) Legacy Amendment - Option B (Amendment No. 3) June 1, 2012

3028 Salton Sea Power Generation L.P. #2 Legacy Amendment - Option B June 1, 2012

3030 Coso Energy Developers (BLM) Legacy Amendment - Option B (Amendment No. 2) May 1, 2012

3050 Salton Sea IV Legacy Amendment - Option B June 1, 2012

3104 Ormesa Geothermal I, II, GEM Legacy Amendment - Option A (Amendment No. 3) June 1, 2012

4030 Dan Bates Legacy Amendment – Option B (Amendment No. 2) May 30, 2012

4036 Kaweah River Power Authority Legacy Amendment - Option B April 30, 2012

5017 Luz Solar Partners Ltd. III Legacy Amendment - Option B June 1, 2012

5018 Luz Solar Partners Ltd. IV Legacy Amendment - Option B June 1, 2012

5019 Luz Solar Partners Ltd. V Legacy Amendment - Option B June 1, 2012

5020 Luz Solar Partners Ltd. VI Legacy Amendment - Option B June 1, 2012

5021 Luz Solar Partners Ltd. VII Legacy Amendment - Option B June 1, 2012

5050 Luz Solar Partners Ltd. VIII Legacy Amendment - Option B June 1, 2012

5051 Luz Solar Partners Ltd. IX Legacy Amendment - Option B June 1, 2012

6004 FPL Energy Cabazon Wind, LLC Legacy Amendment - Option B June 1, 2012

6019 Zephyr Park, LTD Legacy Amendment - Option B April 30, 2012

6024 Ridgetop Energy I, LLC Letter Agreement to allow Ridgetop to curtail on behalf of certain other QFs impacted by substation maintenance February 1, 2012

6024 Ridgetop Energy I, LLC Legacy Amendment - Option B May 1, 2012

6031 EUI Management PH Inc Legacy Amendment - Option B (Amendment No. 7) May 1, 2012

6037 Tehachapi Power Purchase Contract Trust Legacy Amendment - Option B June 1, 2012

6039 Wind Stream Operations, LLC VG1 Legacy Amendment - Option B (Amendment No. 5) April 30, 2012



6042 Wind Stream Operations, LLC VG4 Legacy Amendment - Option B (Amendment No. 6) June 1, 2012

6043 AES Tehachapi Wind, LLC 85A Legacy Amendment - Option B (Amendment No. 5) June 1, 2012

6044 AES Tehachapi Wind, LLC 85B Legacy Amendment - Option B (Amendment No. 5) June 1, 2012

6051 Section 20 Trust Legacy Amendment - Option B May 21, 2012

6052 NAWP Inc [East Wind Proj] Legacy Amendment - Option B May 21, 2012

6055 Coram Energy, LLC Legacy Amendment - Option B May 21, 2012

6057 Cameron Ridge, LLC Legacy Amendment - Option B May 1, 2012

6058 San Gorgonio Westwinds II, LLC Legacy Amendment - Option B April 30, 2012

6063 Desert Winds I PPC Trust Legacy Amendment - Option B June 1, 2012

6065 Sky River Partnership (Wilderness I) Legacy Amendment - Option B June 1, 2012

-11-

6065 Sky River Partnership (Wilderness I)

Transition from IFA to LGIA, due to TRTP upgrades (Amendment No. 8) December 12, 2012

6066 Sky River Partnership (Wilderness II) Legacy Amendment - Option B June 1, 2012

6066 Sky River Partnership (Wilderness II)


6067 Sky River Partnership (Wilderness III) Legacy Amendment - Option B June 1, 2012

6067 Sky River Partnership (Wilderness III)


6087 Section 16-29 Trust (Altech III) Legacy Amendment - Option B May 21, 2012

6089 CTV Power Purchase Contract Trust Legacy Amendment - Option B May 21, 2012

6091 Cameron Ridge, LLC Legacy Amendment - Option B May 1, 2012

6092 Ridgetop Energy II, LLC Letter Agreement to allow Ridgetop to curtail on behalf of certain other QFs impacted by substation maintenance February 1, 2012

6092 Ridgetop Energy II, LLC Legacy Amendment - Option B May 1, 2012

6094 Section 22 Trust (San Jacinto) Legacy Amendment - Option B May 21, 2012

6097 Windland Inc (Boxcar II) Legacy Amendment - Option B (Amendment No. 2) May 21, 2012

6102 Victory Garden Phase IV Partner Legacy Amendment - Option B June 1, 2012



6105 Terra-Gen 251 (Monolith X) Legacy Amendment - Option B May 1, 2012

6106 Terra-Gen 251 (Monolith XI) Legacy Amendment - Option B May 1, 2012

6107 Terra-Gen 251 (Monolith XII) Legacy Amendment - Option B May 1, 2012

6108 Terra-Gen 251 (Monolith XIII) Legacy Amendment - Option B May 1, 2012

6111 Wind Stream Operations, LLC (Northwind) Legacy Amendment - Option A (Amendment No. 4) June 1, 2012

6112 Painted hills wind Developers Legacy Amendment - Option B (Amendment No. 5) May 1, 2012

6113 Desert Winds II Power Purchase Trust Legacy Amendment - Option B June 1, 2012

6114 Desert Wind III PPC Trust Legacy Amendment - Option B June 1, 2012

6234 Oak Creek Energy Systems Inc. Legacy Amendment - Option B April 30, 2012

6365 CalWind May 31, 2012

a) Carson Cogeneration Company (RAP ID 2087) 1

Carson Cogeneration Company (Carson) is a 42 MW firm capacity cogeneration project 2

operating under an SO2 PPA. On May 25, 2012, Carson executed a Legacy Amendment, selecting 3

Options A and C1. Shortly after Carson selected Option C1, the parties began negotiations on an 4

agreement to convert the project’s baseload cogeneration to a dispatchable tolling arrangement. The 5

parties later acknowledged that the terms in Option C1 did not allow enough time to fully negotiate the 6

-12-

complexities of the operational change. As a result, the parties executed Amendment No. 9 to the PPA 1

to extend the number of calendar days from 90 to 365 to finalize the tolling agreement. 2

On March 13, 2013, the parties executed an Amended and Restated PPA (including pro forma 3

EEI Cover Sheet, Toll, and RA Confirms) converting the project to a dispatchable tolling arrangement in 4

accordance with the Legacy Amendment, Option C1. The operational change from baseload QF to 5

dispatchable Exempt Wholesale Generator (“EWG”) is estimated to take effect on April 1, 2013. 6

7

8

9

10

b) Lake Shore Mojave (RAP ID 2808) 11

During the Record Period, Lake Shore Mojave (“Mojave”), a 55 MW topping-cycle cogeneration 12

facility, and SCE executed a Transition PPA, effective May 31, 2012. 13

14

15

16

17

c) Ridgetop Energy, LLC I and II (RAP ID 6024 and 6092) 18

On January 13, 2012, SCE provided notice to Ridgetop Energy I, Ridgetop Energy II, and 19

several other QFs that they would be required to limit their collective output to 250 MW from January 20

23, 2012 until approximately April 20, 2012 in order to accommodate maintenance at Bailey Substation 21

(Bailey Maintenance). 22

The parties agreed that SCE was entitled to perform the Bailey Maintenance as planned and 23

without compensation to Ridgetop I and II (Ridgetop), and SCE and Ridgetop executed a letter 24

agreement to help mitigate the impacts of the Bailey Maintenance. Under the agreement, Ridgetop 25

would curtail on behalf of certain other QFs impacted by the Bailey Maintenance (Ridgetop made 26

separate arrangements with those QFs to be paid for this service), and SCE would not be required to pay 27

-13-

for the Bailey Maintenance curtailments. Specifically, Ridgetop was only required to curtail when total 1

coincident generation in the impacted area reached 250 MW, rather than limiting all generators to an 2

aggregate 250 MW by nameplate. By working with Ridgetop to implement this coincident generation 3

methodology as enabled by the agreement, the overall curtailments required due to the Bailey 4

Maintenance were reduced by approximately 90%. Additionally, the agreement established a settlement 5

methodology whereby Ridgetop would continue to be paid for Goldtown-Lancaster limitation 6

curtailments (See Section C.7(d)(3) below), but not for Bailey Maintenance curtailments. The 7

agreement had the overall benefit of maximizing the amount of renewable generation delivered to SCE’s 8

customers, ensuring SCE’s customers did not pay for any curtailments related to the Bailey 9

Maintenance, and limiting the financial impact of the curtailments on the generators. 10

d) CalWind Resources, Inc. (RAP ID 6365) 11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

-14-

3. Contract Assignment Administration 1

PURPA and CHP contracts typically provide that they may be assigned to other parties based 2

upon the written consent of the counterparty, which may not be unreasonably withheld. PURPA and 3

CHP contract counterparties may request SCE’s consent to assignment of their contracts for many 4

reasons, including, among others, the project’s sale or transfer to a new entity or the contract’s 5

assignment to a lender as security for a loan. Table IX-4 lists the three PURPA contract assignments to 6

which SCE consented during the Record Period; no CHP contracts were assigned. 7

Table IX-4 PURPA Contract Consents and Consents to Assignments


4. Uncontrollable Force Administration 8

SCE’s SO2, ISO4 contracts, many of its NEG contracts, and CHP contracts include provisions 9

that may excuse a PURPA or CHP project from performing certain contractual obligations to the extent 10

the project can demonstrate that the occurrence of an uncontrollable force prevented the project from 11

performing such obligations. An uncontrollable force is any circumstance beyond a project’s reasonable 12

control as defined in the applicable agreements, and is often known as a force majeure. 13

Whenever a PURPA or CHP contract holder claims that an uncontrollable force caused it to fail 14

to meet its contractual obligations, SCE undertakes the following activities: 15

� Determines whether the claim was submitted within the contractually-required period, 16

which is typically two weeks. 17

� Requires that the counterparty submit sufficient evidence to substantiate the claim that an 18

uncontrollable force event occurred. This may include meteorological or weather reports 19

to support a claim of weather damage, construction and equipment specifications, 20

RAP ID

Project Type of Assignment or Consent Date Signed

4030 Dan Bates Consent to Trust to Bypass Trust May 18, 2012

4030 Dan Bates Consent to Assignment 1 Trustees to Trust May 30, 2012

4030 Dan Bates Consent to Assignment 2 Trust to Bypass Trust May 30, 2012

-15-

manufacturer maintenance manuals and bulletins, the project’s operations and 1

maintenance / repair logs, copies of insurance claims, damage assessments, failure 2

reports, or other relevant materials. 3

� Evaluates whether the suspension of performance was of no greater scope and of no 4

longer duration than was required by the uncontrollable force, and that the PURPA 5

contract holder used its best efforts to remedy its inability to perform. 6

If SCE grants the claim, and if the contract does not provide otherwise, the PURPA or CHP 7

contract counterparty will continue to receive firm capacity payments for up to 90 days from the 8

occurrence, despite a failure to deliver power to SCE. Such payments are typically based upon the 9

project’s historical performance during the affected time period. In addition, during the period of an 10

approved uncontrollable force event, delivery requirements under the contract are excused. 11

Table IX-5 shows the status of the 14 uncontrollable force claims tendered to SCE or pending 12

during the Record Period: 13

-16-

Table IX-5 PURPA Uncontrollable Force Claims Tendered and/or Pending


5. Forced Outage Claim Administration 1

In general, a forced outage claim is approved when a project operating pursuant to a PURPA or 2

CHP contract is otherwise capable of generating electricity, but is forced to shut down either because 3

SCE is unable to receive the generation due to abnormal system conditions or because of a failure in 4

RAP ID

Project Date and Event Status

2058 Sycamore Cogeneration Company

May 2-4, 2012 - Mojave Pipeline Service Interruption

Credited 58 hours of Uncontrollable Force credit.

2205 E. F. Oxnard Incorporated

12:10 on May 25, 2012 - EF Oxnard was tripped off line due to a phase to ground fault in SCE’s OXGEN substation

Credited production for 8 hours and 50 minutes

2801 Kern River Cogeneration Company -

May 2-4, 2012 - Mojave Pipeline Service Interruption

On May 15, 2012, SCE provided notice to KRCC of a Force Majeure for the outage pertaining to the dispatch units. On May 17, 2012, KRCC provided notice to SCE of a Force Majeure related to the same incident, but as it pertained to KRCC's base load units. Base load units received Uncontrollable Force credits for 59 hours. Dispatch units received a reduced Maximum Availability Payment.

3004 Del Ranch, LTD., (Niland #2)

October 22, 2012 - SCE Transmission Curtailment on 220 kV line from Mirage - Ramon in IID

Denied. Not an Uncontrollable Force as the term is defined in the PPA

3006 Vulcan/Bn Geothermal



3011 Terra-Gen Dixie Valley, LLC

August 22-23, 2012 - Edison (Bishop Control) tripped the Dixie Valley transmission line via Remedial action Scheme due to inclement weather in the Bishop area

6 hours of on-peak credited, 9 hours of mid-peak credited, and 4 hours of off-peak credited.

3025 Salton Sea Power Generation L.P. #3

July 3, 2012 - Facility Shutdown due to large leak on the brine processing system











3039 Salton Sea Power Generation Co #1



3039 Salton Sea Power Generation Co #1



3050 Salton Sea IV July 3, 2012 - Facility Shutdown due to large leak on the brine processing system


3050 Salton Sea IV October 22, 2012 - SCE Transmission Curtailment on 220 kV line from Mirage - Ramon in IID


-17-

SCE’s operations. An approved forced outage claim generally has the same effect upon the project as an 1

approved uncontrollable force claim; namely, the project’s performance requirements are excused 2

during the period of the forced outage. The forced outage may also be contractually obligated and 3

defined in the contract. 4

There is no deadline specified in the PURPA or CHP contracts by which the counterparty must 5

notify SCE that a forced outage has occurred. However, SCE considers the promptness with which the 6

claim is submitted, among other factors, in determining whether to grant the claim. In assessing the 7

claim, SCE verifies that an outage occurred, whether the outage resulted from an event that constitutes a 8

forced outage under the contract, and the magnitude and duration of the outage. If appropriate, SCE 9

analyzes meter data, substation logs, and system operations reports in reviewing the claim. 10

Table IX-6 shows the status of 37 forced outage claims tendered to SCE or that were pending during 11

the Record Period. 12

-18-

Table IX-6 PURPA Forced Outage Claims



1090 L.A. Co. Sanitation Dist.

January 3, 2012 - The CB for the Walnut-Cortez-Merced 66 kV line opened and remained opened due to a separation of a conductor at the Walnut Substation. The outage was caused by an under voltage trip on the Edison breaker.

3 hours of mid-peak credited for an average offline capacity of 41.590 MW.


March 8, 2012 - Under voltage experienced on the associated 66 kV line. A 66 kV breaker opened inside the Hilgen substation. After further investigation it was determined the cause of the outage was by a contractor hired by the Seller.

Claim denied


May 16, 2012 - Edison breaker opened inside the Hilgen Substation. Balloons caused the power interruption.

2 hours of mid-peak credited and 1 hour off-peak credited for an average offline capacity of 36.594 MW.


May 22, 2012 - Edison breaker opened. SCE investigated the county's claim of one hour production loss.

Claim denied due to maintenance credit during the same time.

2042 Cal State Channel Islands Site Authority

October 15, 2012 - Operations were interrupted due to a loss of power on the 66 kV transmission lines connecting CSUCI Power to the Colonia substation when SCE's breaker CB01 opened disconnecting the plant from the power grid.

3 hours mid peak credited.

2050 Ripon Cogeneration, Inc.

December 18-19, 2012 - Failure of a lightning arrestor on the B phase of the transformer at Simpson Substation caused unit to trip offline.

8 hours of mid-peak credited, 5 hours of off-peak credited, and 6 hours of super off-peak credited for an average offline capacity of 34.246 MW.

2801 Kern River Cogeneration Company - Unit #1

January 1, 2012 - Flashbacks - Failed to reignite primaries 3.5 hours off peak and .75 hours of super off peak credited.

2801 Kern River Cogeneration Company - Unit #1

January 9, 2012 - Shutdown to avoid emissions exceedance 2.75 hours off peak and 2 hours of super off peak credited.

2801 Kern River Cogeneration Company - Unit # 1

January 17, 2012 - Shutdown to avoid emissions exceedance 0.5 hours off peak and 2 hours of super off peak credited.


January 19, 2012 - Shutdown to avoid emissions exceedance

2.5 hours off peak and 1 hour of super off peak credited. Remainder not credited. Exceed 3% allowance per PPA.


January 16, 2012 - Shutdown to avoid emissions exceedance 1.5 hours mid peak credited.


January 24, 2012 - Flashbacks - Failed to reignite primaries 0.75 hours mid peak credited.

2801 Kern River Cogeneration Company - Unit #

February 26, 2012 - Unit 1 - Volts / Hertz Card Failure in Excitation System

5 hours off peak and 2 hours of super off peak credited. Remainder not credited. Exceed 3% allowance per PPA.


February 5, 2012 - Shutdown to avoid emissions exceedance 2.75 hours off peak credited.


February 28, 2012 - Excitation System Maintenance

3 hours mid peak and .75 hours of super off peak credited. Remainder not credited. Exceed 3% allowance per PPA.

-19-


May 2, 2012 - Shutdown to avoid emissions exceedance 1.75 hours off peak and 4 hours of super off peak credited.


May 11, 2012 - Shutdown to avoid emissions exceedance .5 hours of super off peak credited. Remainder not credited. Exceed 3% allowance per PPA.


May 18, 2012 - Unit tripped during on-line wash 1 hour of mid peak credited


June 6-7, 2012 - Replaced #2 secondary burner to avoid emissions exceedance.

1.5 hours of mid peak and 6.5 hours off peak credited. Remainder not credited. Exceed 3% allowance per PPA.


June 7, 2012 - Unit 3: Replaced #1 secondary burner to avoid emissions exceedance

1.25 hours of mid peak and 4 hours on peak credited. Remainder not credited. Exceed 3% allowance per PPA.


June 7, 2012 - Reinstalled #2 secondary burner to avoid emissions exceedance

1.25 hours of on peak and 3 hours mid peak credited. Remainder not credited. Exceed 3% allowance per PPA.


June 12, 3012 - Swapped #2 and #8 secondary burners to avoid emissions exceedance

No hours credited. Exceed 3% allowance per PPA.


July 7 to July 8, 2012 -Repair Leaking Steam Line 10.5 hours off peak credited.


July 17, 2012, - Shutdown to avoid emissions exceedance 1.5 hours on peak credited.


August 16, 2012 – Flashbacks 1.5 hours on peak credited.


August 26, 2012 - Failed North Exhaust Flame Blower Contactor 7 hours off peak credited.


August 26, 2012 – Flashbacks 1 hour off peak credited.


October 7, 2012 - Loss of Flame - Cleaned Flame Detectors No hours credited. Exceed 3% allowance per PPA.


October 11, 2012 - Unit Tripped Off During Testing No hours credited. Exceed 3% allowance per PPA.


October 11, 2012 - Shutdown to avoid emissions exceedance No hours credited. Exceed 3% allowance per PPA.


October 24, 2012 - Shutdown to avoid emissions exceedance No hours credited. Exceed 3% allowance per PPA.


October 24-25, 2012 - Hydrogen Leak - Repaired Leak at Bore Plug



October 25-26, 2012 - Gas Leak - Replaced a Secondary Fuel Nozzle Elbow



November 9, 2012 - Flashbacks - Shutdown to avoid emissions exceedance 3 hours mid peak credited.

-20-


December 5, 2012 - Flashbacks - Cleaned Flame Detectors 2.25 hours mid peak credited.


December 13, 2012 - Flashbacks - Reset and Restart Unit 8.25 hours mid peak and 6 hours super off peak credited.

5005 Sunray Energy, Inc. August 30, 2012 - An oil-filled circuit breaker opened in the Edison switchyard due to a fault on the Edison side of the system.

Claim denied due to maintenance credit during the same time.

6. Dispute Resolution and Litigation 1

During the Record Period, a number of PURPA and CHP projects invoked the dispute resolution 2

provisions of their contracts. Below is an overview of significant claims from the Record Period. 3

a) Watson Cogeneration Company (RAP ID 2053) 4

On December 19, 1984, Watson Cogeneration Company (“Watson”) executed a power purchase 5

contract with SCE. The agreement expired on December 31, 2007.However, in D.07-09-040, the 6

Commission ordered SCE to extend the non-price terms of its expiring PURPA contracts if the project 7

counterparties so desired.19 Watson elected to accept the extension. 8

Watson reserved their rights to the original contract payments for January 2008 through April 9

2008, contending that the termination date of its PPA was April 6, 2008. However, as noted in SCE’s 10

April 2008 ERRA filing,20 SCE contends that Watson is not entitled to receive energy and capacity at 11

the price set forth in the original PPA because it expired December 31, 2007. The dispute laid dormant 12

until Watson notified SCE on November 7, 2011 that it filed suit against SCE in Superior Court on 13

November 3, 2011 due to imminent statute of limitation issues regarding their claim. 14

On August 17, 2012, SCE filed a motion for summary judgment, which was granted by the court 15

on November 26, 2012. The parties continue to litigate in Superior Court one final claim related to this 16

dispute. 17

19 The applicable energy and capacity prices are set forth in D.07-09-040. 20 A. 08-04-001 Exhibit SCE-2, p. 13, Table IX-7.

-21-

b) CalEnergy (RAP IDs 3004, 3006, 3009, 3025, 3026, 3028 & 3050) 1

Pursuant to the Settlement, SCE executed seven Option B Legacy Amendments21 with 2

CalEnergy Operating Corporation. The Legacy Amendments were executed on May 21, 2012 with an 3

effective date of June 1, 20124

5

6

7

c) Ormesa Geothermal I (RAP ID 3104) 8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

21 See discussion in Section B.2 of this Chapter IX describing Legacy Amendments offered per the QF Settlement.

-22-

1

2

3

d) Dutch Energy (RAP ID 6095) 4

5

6

7

8

9

10

11

12

7. Contribution In Aid of Construction (CIAC) Tax 13

Some PURPA and CHP contracts require that the counterparty either (1) construct and transfer 14

ownership of the interconnection facilities to the utility or (2) pay the utility for building the project 15

intertie. In 1986, the Internal Revenue Code was amended by the Tax Reform Act of 1986 to provide 16

that these transfers of property and/or payments of money may be determined by the Internal Revenue 17

Service (IRS) to be taxable income to SCE as CIAC. In 1988, the IRS clarified that such transfers only 18

become taxable under the circumstances described in the IRS’s regulations. 19

Counterparties to PURPA and CHP contracts are ultimately responsible for CIAC tax, also 20

referred to as the income tax component of contributions (ITCC) imposed on the utility as a result of the 21

projects’ interconnection arrangements. Pursuant to D.94-06-038, such parties can avoid the 22

requirement of making a cash deposit to securitize this obligation by providing either (1) a certification 23

of adequate tangible net worth or (2) a letter of credit. To comply with D.94-06-038, these parties must 24

execute an indemnity agreement that provides for the posting of a letter of credit or incorporates the 25

annual certification requirements. SCE monitors compliance with these indemnity agreements and for 26

-23-

the Record Period no additional security was received. SCE notes that during the Record Period,1

2

8. Contract Termination 3

17 PURPA contracts totaling 235 MW terminated during the Record Period. Many PURPA 4

contracts provide that the project has a unilateral right to terminate. In some instances, the seller elects 5

to terminate due to a shutdown of the project’s host facility, or for other business reasons. Other 6

contracts simply expire. In the Record Period, a number of contracts terminated and were replaced with 7

Transition Agreements per the QF Settlement. Table IX-7 below identifies the terminations that 8

occurred during the Record Period. 9

-24-

Table IX-7 PURPA Contract Terminations


9. Collateral Verification 1

SCE has a variety of cash and non-cash deposits that are collected from energy suppliers in the 2

procurement process. There are two types of collateral held by SCE for PURPA and CHP contracts, 3

ITCC and Performance Assurance. SCE has assigned its Credit Risk & Collateral Management group to 4

RAP ID Project Net On-line Capacity (MW)

Contract Type Termination Date

1102 Hanson Aggregates WRP, Inc. 0.25 SO1 March 1,20121

2003 Rhodia, Inc. 5 SO1 December 12, 20124

2007 Searles Valley Minerals Inc. 15 RSO1* May 31, 20123

2019 U.S. Borax 45 RSO1* May 31, 20123

2078 Lake Shore Mojave, LLC 55 NEG* May 31, 20123

2206 Berry Petroleum Company (Newhall I) 21.7 SO2* May 31, 20123

2224 Berry Petroleum Company (Newhall II) 19.8 RSO1* May 31, 20123

2802 City of Palm Springs - Municipal 0.38 RSO1* August 1, 20123

2803 City of Palm Springs - Sunrise 0.22 RSO1* August 1, 20123

4010 Calleguas MWD - Unit 1 0.55 ISO4 September 30, 20124

4017 Irvine Ranch Water District 0.19 RSO1* May 31, 20122

4028 Lower Tule River Irrigation District 1.5 ISO4* July 31, 20123

5233 Sierra Suntower 4.2 NEG* May 31, 20123

6006 Mogul Energy Partnership I 4 NEG June 24, 20124

6009 San Gorgonio Wind Farms, Inc. I 3.03 NEG* March 22, 20122

6060 Calwind Resources Inc. 9 ISO4* May 31, 20123

6064 San Gorgonio Farms, Inc. 24.47 ISO4* March 22, 20122 6308 Mesa Wind Power Corporation 30 RSO1* April 8, 20122

Total MW 235

*PPAs on extensions per D.07-09-040

Notes:

1) Seller elected to terminate PPA.

2) Extension Agreement expired.

3) Extension Agreement expired; executed a new PPA.

4) PPA Expired.

-25-

handle the administration and tracking of this collateral. The contract managers within SCE’s RAP 1

Group still serve as the primary contact for collateral issues; however, Credit Risk & Collateral 2

Management will directly handle SCE’s routine transactions with the counterparties. Contract managers 3

enter key collateral data into WES so that the basic data is readily available. At the end of the Record 4

Period, 5

No significant exceptions occurred during the Record Period. 6

10. Other Contract Administration Activities 7

a) Desert View Power (RAP ID 1038) Application 12-06-017 8

Desert View Power (DVP), a 45 MW biomass facility, has been providing energy to SCE 9

pursuant to a Qualifying Facility ISO4 contract since December 20, 1991. In March of 2011, DVP 10

approached SCE, expressing concern over DVP’s ability to continue operations based on short-run 11

avoided cost (SRAC) pricing. DVP made bilateral pricing proposals to SCE in an effort to reach an 12

agreement on a price that would sustain the project. None of DVP’s pricing offers presented sufficient 13

value for SCE’s customers. Furthermore, due to the substantial capacity repayment obligation due by 14

DVP, SCE was unwilling to offer, and the DVP PPA did not provide, a way to terminate the PPA that 15

was agreeable to both parties. 16

On April 6, 2012, the parties amended the PPA whereby deliveries are suspended for a number 17

of years (the Suspension Period) – thereby allowing DVP to sell power to a third party – and SCE would 18

have the option to resume deliveries under the PPA at the end of the Suspension Period at the price and 19

terms agreed upon by the parties in the Amendment. DVP has located a third party purchaser for its 20

power during the Suspension Period. 21

On June 29, 2012, SCE filed Application No. 12-06-017 with the California Public Utilities 22

Commission (CPUC) seeking approval of the amendment to the DVP PPA. On December 5, 2012, the 23

CPUC issued a final decision approving the application (D. 12-11-035). 24

-26-

b) Retroactive Payment Calculations for US Borax (RAP ID 2806) and Berry 1

Petroleum (RAP ID 2805) 2

As part of the CHP Settlement, U.S. Borax and Berry Petroleum were allowed to execute new 3

firm capacity Transition PPAs. Section 3.4.4 of the CHP Settlement Term Sheet entitles U.S. Borax and 4

Berry Petroleum to a retroactive payment for the period of January 1, 2010 to May 31, 2012, based upon 5

the new terms of the Transition PPA. These projects, originally operating under firm capacity QF PPAs, 6

executed non-firm, as-available capacity PPAs (RSO1s) once their original PPAs expired, since firm 7

capacity PPAs were not available at that time. Section 3.4.4 allows these projects to be retroactively 8

compensated from January 1, 2010 to May 31, 2012 as if they had operated under the terms of the new 9

firm capacity Transition PPA. 10

In determining the retroactive payment amount owed to U.S. Borax and Berry Petroleum, SCE 11

followed the terms of the Transition PPA, calculating the amount that each counterparty would have 12

received for its deliveries under the Transition PPA. This amount was reduced according to specific 13

provisions in the Transition PPA that require SCE to deduct certain fees and penalties, such as 14

Scheduling Coordinator fees, Schedule Delivery Deviation fees, and Mean Absolute Error (MAE) 15

Failure penalties. The retroactive payment adjustments for U.S. Borax and Berry Petroleum were 16

completed in December 2012. 17

18

C. Contract Compliance 19

Compliance programs have been developed to ensure that PURPA and CHP projects adhere to 20

the terms of their contracts, and to integrate those projects effectively to the electric system grid. This 21

section discusses the following contract compliance programs: (1) capacity performance; (2) metering 22

energy deliveries; (3) prescribed dispatch; (4) protection equipment testing; (5) efficiency monitoring; 23

(6) scheduled maintenance; (7) wind operations; (8) insurance verification; and (9) forecasting and 24

scheduling accuracy. 25

-27-

1. Capacity Performance Programs 1

SCE’s capacity performance monitoring programs and activities assist in ensuring that SCE’s 2

customers receive the firm capacity for which SCE has contracted. There are two major programs: the 3

annual contract capacity demonstration (CapDemo) program, and the summer capacity performance 4

(CapPerformance) program. 5

a) CapDemo Program 6

The CapDemo program applies to those PURPA and CHP contracts that provide payment for 7

firm capacity and contain a capacity testing clause. These facilities are required to achieve and reliably 8

sustain 100 percent of their firm contract capacity for each metering interval (typically 15 minutes) 9

during a specified period of testing (typically six hours during an on-peak period), or as otherwise 10

specified either in the contract or other agreements between SCE and the counterparty. This 11

performance test simulates the condition described in most contracts requiring the project to make best 12

efforts to provide full contract output when a system emergency is declared. Most firm capacity 13

contracts contain a firm capacity reduction clause that provides a remedy if the generator is unable to 14

provide the required capacity during the test. Typically, the remedy is a reduction of firm capacity to the 15

level demonstrated during the test.22 16

The steps involved in implementing the CapDemo program include scheduling mutually-17

agreeable test dates, visits by SCE personnel to the facility to ensure that the test protocols are properly 18

followed, analysis of the regular revenue meter data for pass or fail status, communicating the results to 19

the project, and administering the appropriate remedy for those projects that fail. Demonstrations are 20

generally performed during the summer season on-peak hours from June 1 to September 30. Longer test 21

periods specified in a few of the contracts also include hours from the mid-peak and off-peak periods. 22

During the Record Period, SCE witnessed 38 demonstrations and sent notices of pass/fail status 23

to all of the facilities. Of the 38 projects, 33 passed their initial demonstration. Three demonstrations 24

22 SCE has historically experienced disputes with projects operating pursuant to PURPA contracts regarding the

appropriate capacity reduction in the event of a CapDemo test failure.

-28-

were each deemed a technical “failure” that was deemed an administrative pass. Two facilities failed 1

the demonstration. The circumstances regarding the three administrative passes and the two failures are 2

as follows: 3

(1) CSU Channel Islands Site Authority (RAP ID 2042) 4

CSU Channel Islands Site Authority, a topping cycle cogeneration facility, failed to deliver its 5

specified level of firm contract capacity of 26,500 kW during a number of 15-minute metering intervals 6

within the six hour demonstration period. The lowest facility output was only 292 kW (1.1%) below 7

firm contract capacity. This amount was determined to be within the tolerance of the demonstration. 8

The facility was issued an administrative pass. 9

(2) Salton Sea Power Generation Co #3 (RAP ID 3025) 10

Salton Sea Power Generation Co #3, a geothermal facility that utilizes multiple flash technology, 11

failed to deliver its specified level of firm contract capacity of 47,500 kW. During the 14:00 to 15:00 12

hour, there was a 5 minute downward spike in unit output to 45,876 kW; however, this negotiated 13

contract has a demonstration protocol that requires the use of hourly meter data. The hourly metered 14

amount was 47,379 kW. The facility output was only 121 kW (0.3%) below the required firm contract 15

capacity during this single hour. This amount was determined to be within the tolerance of the 16

demonstration. The facility was issued an administrative pass. 17

(3) Coso Energy Developers (BLM) (RAP ID 3030) 18

The BLM-East and BLM-West complexes at the Coso Known Geothermal Resource Area, a 19

multiple flash technology geothermal facility, failed to deliver the specified level of firm contract 20

capacity of 67,500 kW. During the 15-minute interval 15:15 to 15:30 hours, the facility output dropped 21

to 67,180 kW. The facility output was only 320 kW (0.5%) below the required firm contract capacity. 22

This amount was determined to be within the tolerance of the demonstration. The facility was issued an 23

administrative pass. 24

(4) Ormesa Geothermal 1 (RAP ID 3104) 25

The Ormesa Geothermal complex at the East Mesa Known Geothermal Resource Area, a 26

multiple unit binary technology geothermal facility, failed to provide the specified level of 27

-29-

demonstration capacity of 46,500 kW for the entire six-hour demonstration period. The negotiated 1

demonstration protocol for this contract utilized metering installed for demonstrations. The metering 2

recorded data over 5-minute metering intervals. Per the demonstration protocol, failure to deliver the 3

demonstration capacity over any metering interval was subject to a payment of liquidated damages of 4

$50 per kW. The lowest recorded output was 39,576 kW during the 16:50 to 16:55 interval. The 5

payment of these liquidated damages was the subject of a settlement agreement as discussed above in 6

section B.7(c). 7

(5) Desert Power (RAP ID 4008) 8

Desert Power is a small, run-of-the-river hydroelectric generator. As in past years, Desert Power 9

failed to demonstrate firm contract capacity in 2012. The capacity of the unit was restricted by a lack of 10

river water, leaking intake structures, and faulty diversions that reduced the available water flow to the 11

facility. Desert Power’s nonstandard contract contains no explicit provisions for capacity reduction; 12

however, the project is being penalized with a 0.5 capacity payment multiplier. This penalty is based on 13

an availability requirement in Desert Power’s contract with SCE, which is triggered if the project fails to 14

deliver its contract capacity when required on two consecutive occasions. In this case, the two 15

consecutive failures were the CapDemo test and a system emergency failure. 16

b) CapPerformance Program 17

Most PURPA and CHP contracts with firm capacity provisions require that the project achieve a 18

minimum performance factor (as more specifically defined in the applicable contract) of 80% of its firm 19

contract capacity for the on-peak periods during the peak months of June, July, August, and 20

September.23 If the project fails to meet this minimum requirement for any month, it is placed on 21

probation beginning the month following the failure. Probation generally continues through September 22

of the following year. Therefore, depending on which summer month the project first fails, the 23

23 Many firm capacity PURPA and CHP contracts also contain provisions enabling projects to earn bonus payments for

exceeding minimum contract performance requirements during both the summer and winter months. See the discussion under “Performance Bonus” in E.1 of this chapter.

-30-

probation period can last between 12 and 15 months, subject to SCE’s discretion to shorten the period 1

based on obtaining the best customer outcome for each case. If a project fails to meet the minimum 2

performance factor requirement during any month of its probationary period, its contract capacity may 3

be reduced and / or it can lose its eligibility for winter bonus payments pursuant to the terms of the 4

contract. A project can return to normal status at the end of probation if it satisfies the peak performance 5

requirement during all months of the probationary period. 6

During the Record Period, 46 PURPA contracts were subject to the summer capacity 7

performance provisions for the months of June through September 2012. Four projects failed their 8

performance obligation in at least one summer month during the on-peak delivery period. Status of each 9

of these projects is shown in Table IX-8 below. 10

Table IX-8 CapPerformance Failures


2. Metering Energy Deliveries 11

SCE uses meter and schedule data to calculate payments owed to PURPA and CHP projects. 12

SCE also forwards PURPA and CHP project meter data to the CAISO for operational and settlement 13

purposes. 14

RAP ID Project Event Status

2050 Ripon Cogeneration LLC Failed Failed summer CapPerformance. Are not receiving winter bonus capacity payments; to be placed on probation for upcoming summer peak months.

3028 Salton Sea Power Generation Co #2 Failed Failed summer CapPerformance. Are not receiving winter bonus capacity payments; may be placed on probation for upcoming summer peak months pending review of IID curtailments during on-peak periods.

3039 Salton Sea Power Generation Co #1 Failed Failed summer CapPerformance. Are not receiving winter bonus capacity payments; may be placed on probation for upcoming summer peak months pending review of IID curtailments during on-peak periods.

6213 BNY Western Trust Company Failed Failed summer CapPerformance. Are not receiving winter bonus capacity payments; to be placed on probation for upcoming summer peak months

-31-

a) PURPA and CHP Projects Within SCE’s Territory 1

SCE uses three types of “interval” metering for PURPA projects located in its service area: (1) 2

real time energy metering (RTEM); (2) interval meters; and (3) CAISO meters. Each of these is 3

described below. There is one extremely small project that uses a meter that provides only monthly 4

totals read from displays on the meter face. 5

SCE provides settlement ready meter data to the CAISO for legacy PURPA and CHP generators 6

in its service territory that are not required to have CAISO meters. Readings from all these RTEM and 7

interval meters are accumulated into hourly totals and aggregated according to the CAISO delivery point 8

(global resource ID). Applicable distribution loss factors and radial loss factors are then applied. The 9

final adjusted hourly total generation for each project that share CAISO delivery points (also known as 10

global resource IDs) are aggregated by ID. The resulting data are compiled into a Meter Data Exchange 11

Format file by SCE’s MV-90 meter reading system and reported to the CAISO for settlement by 12

uploading into their OASIS system. 13

(1) The RTEM Process 14

SCE uses the RTEM process to measure most of the production pursuant to PURPA and CHP 15

contracts. At the end of the reporting period, there were 159 RTEM meters on 141 PURPA and CHP 16

contract projects. Some installations have multiple meters. These RTEM meters generally measure 17

energy sold to SCE, energy supplied to the facility by SCE, and reactive power supplied by SCE. The 18

RTEM meters store data internally, and the data are transmitted to a central computer every 15 19

minutes.24 Depending on the best pathway available at the site, the data transmission occurs through the 20

SCE-owned radio packet network called NETCOM, through a cell phone system, or through the 21

domestic telephone system. If the communication system fails, the meters can still be read manually 22

using a handheld device. The data are transferred from the central computer to the wholesale energy 23

system (WES) (SCE’s comprehensive contract management/administration computer-based system), 24

which is used to generate payment statements for these projects. 25 24 The central computer also supports SCE’s billing, generation grid operations, and energy accounting systems.

-32-

(2) Interval Meters 1

Simpler meters are used on very small projects that are in areas still covered by manual meter 2

readers. These simple meters are all-electronic interval meters that contain an internal recorder. These 3

meters have replaced the obsolete mechanical meters and the external DataStar recorders that were used 4

in the past when the cost of RTEM meters was not justified. Each month, SCE visits the facility to 5

collect the meter data, using a laptop computer with an optical link that connects to the recorder. The 6

data is then transferred to a central computer via SCE’s internal network, and then to WES to generate 7

monthly payment statements. At the end of the reporting period, there were 7 interval meters in use for 8

PURPA projects. 9

(3) CAISO Meters 10

At the end of the reporting period, one project operating pursuant to a PURPA contract used a 11

total of four CAISO meters (four meters for one contract), and one project operating pursuant to CHP 12

contract used a total of two CAISO meters (two meters for one contract). CAISO meters are four-13

quadrant interval meters that measure forward and reverse watts and VARs. The meters are capable of 14

communicating with a remote system for data collection. The CAISO reads these meters directly for 15

settlements. SCE also reads these meters remotely. The data are used in various ways as provided in 16

the contracts. 17

b) Out-of-Service Territory PURPA Projects 18

At the end of the reporting period, SCE had 12 PURPA projects metered outside of SCE’s 19

service territory (OST). Most of the OST projects are located within IID’s service area. Energy is 20

delivered by the local utility to SCE over that utility’s interties with SCE.25 SCE receives the quantity of 21

energy represented by, and pays these PURPA projects based upon, hour-by-hour energy delivery 22

schedules from the delivering utility. The schedules are established one day ahead and are adjusted in 23

25 The special administration procedures discussed in this section are not applicable to the KRCC (RAP ID 2801),

Sycamore (RAP ID 2058), and Terra-Gen Dixie Valley (RAP ID 3011) projects, which are located outside of SCE’s normal service territory, but do not utilize an interconnecting utility because they are directly connected to SCE’s system and therefore are directly metered by SCE. These projects are not discussed in this section.

-33-

real time between SCE, the delivering utility, and the CAISO. The final schedule for each hour is 1

retained in SCE’s GenManager System that is operated by SCE’s Energy Supply & Management 2

Department. The GenManager system replaced the Power Bidding System used in the past. 3

The projects in IID’s service territory are covered by a single aggregated schedule in 4

GenManager. Because each project must be paid separately, IID creates a spreadsheet of hourly meter 5

and schedule data and e-mails the final schedule data at the end of each month to SCE’s Power 6

Procurement Finance department. The data are then recorded in WES and verified against the 7

GenManager data. For more discussion on SCE’s payment administration of its OST PURPA contracts, 8

see Section E.2 of this chapter. 9

3. Prescribed Dispatch 10

During the Record Period, there were two PURPA projects that contained provisions permitting 11

SCE to exercise a prescribed dispatch option. These provisions allow SCE to prescribe periods when 12

the project must either limit energy deliveries or receive a lower price for energy not curtailed, so as to 13

render SCE’s customers economically indifferent. By exercising this right when SCE expects to 14

experience minimum load conditions, higher cost PURPA contract energy is curtailed, allowing for 15

lower cost market purchases and therefore reduced costs to SCE’s customers. The following activity 16

occurred during the Record Period: 17

a) Wheelabrator Norwalk (RAP ID 2064) 18

This project has an annual contractual dispatch requirement and was dispatched for 1,000 hours 19

as specified in the contract. 20

b) E.F. Oxnard (RAP ID 2205) 21

E.F. Oxnard has the option to participate in prescribed dispatch as specified in their contract. 22

They did not select the option to participate in prescribed dispatch for this period. 23

4. Protection Equipment Testing Program 24

The protection equipment testing program (Protection Program) provides for the uniform 25

implementation of the standards and requirements contained in SCE’s Tariff Rule No. 21, as applicable 26

to PURPA projects. The Protection Program assures that any protection equipment owned by a party 27

-34-

operating a facility pursuant to a PURPA contract that directly interfaces with SCE’s system is regularly 1

tested in accordance with contractual requirements. Most PURPA contracts require that protection 2

equipment be tested at regular intervals of one, two, or four years depending on connection voltage. 3

Non-compliance with applicable protection equipment standards may subject SCE and its 4

customers to greater risk that generation equipment will not disconnect as required if it malfunctions. 5

This could cause damage to the project’s equipment and introduce unwanted and possibly harmful 6

voltage fluctuations into SCE’s system or could cause a portion of the SCE system to shut down, 7

interrupting service to customers. There are also some conditions that could cause harmonics and other 8

power quality problems. 9

During the Record Period, SCE received and processed 3 protection testing reports from 10

counterparties. Receipt of a report indicates that a licensed electrician inspected the protective relays. 11

SCE will deny a forced outage claim for any project that does not provide the required reports because 12

SCE will not have had proof that equipment was properly maintained as required by SCE's Tariff Rule 13

No. 21. 14

5. QF Efficiency Monitoring Program 15

In D.91-05-007, the Commission authorized the utilities to monitor the operations of 16

cogenerators, as well as small power producers that use supplemental fossil fuel, to ensure that they are 17

in compliance with FERC operating and efficiency standards. The program implementing this decision 18

is known as the QF Efficiency Monitoring (QFEM) program. 19

Originally, state regulations permitted suspension of contract payments and disconnection of 20

PURPA projects from parallel operation for failure to comply with FERC standards. Subsequent 21

litigation and Commission decisions have modified the QFEM program, based on a determination that 22

federal law preempted the state’s regulations. Currently, only FERC can determine if a project is 23

compliant and prescribe corrective actions in the event of noncompliance. However, PURPA projects 24

are still required to submit operating data to utilities annually to demonstrate compliance with FERC 25

standards. When it is cost effective, SCE will take measures necessary to file complaints at FERC with 26

respect to projects operating pursuant to a PURPA contract that fail to come into compliance after 27

-35-

notice. PURPA projects found to be out of compliance by FERC may lose their QF status and be 1

ordered to refund overpayments to the utility. 2

During the Record Period, SCE determined that all PURPA projects that submitted complete 3

operating, efficiency, and fuel use data for calendar year 2011 met FERC standards for that year.26 SCE 4

continues to follow-up with five other PURPA cogeneration projects that have not submitted data. 5

These five projects are identified in Table IX-9 below. 6

Table IX-9 Projects That Failed to Submit Operating and Efficiency Data

for Calendar Year 2011

6. Scheduled Maintenance 7

The scheduled maintenance program provides for uniform implementation and verification of the 8

scheduled maintenance procedures in each firm capacity PURPA or CHP contract. Under all standard 9

offer contracts, and some nonstandard contracts, PURPA and CHP projects are responsible for providing 10

advance notice to SCE of reductions in capacity availability due to scheduled maintenance. PURPA and 11

CHP projects that give proper notice of their scheduled maintenance outages receive an “allowable 12

maintenance hours” credit to be used in calculating their monthly firm capacity payment. Projects that 13

reduce or cease generation without proper notice do not receive scheduled outage credit and, as a result, 14

26 Data is requested on an annual basis, so SCE receives 2011 data in 2012.

RAP ID Project Name Size (kW)

Notes

2178 The Claremont Club 180 Data promised by end of year-not received. Follow-up request submitted.

2210 Crimson Resource Management 500 Project not currently operating. 2802 City of Palm Springs - Muni 1,300 Terminated. New Transition Contract. 2803 City of Palm Springs - Sunrise 650 Terminated. New Transition Contract. 2413 St. Johns Hospital and Health Center 1,080 Data promised by end of year; not received.

Follow-up request submitted.

-36-

may be unable to earn their full capacity payment. PURPA and CHP projects are required to make all 1

reasonable efforts to schedule maintenance during SCE’s off-peak winter months (October – May). 2

During the Record Period, 42 PURPA projects made a total of 859 requests to schedule 3

maintenance; 2 CHP projects submitted 4 such requests. SCE approved 769 of those requests for 4

PURPA projects and 4 for CHP projects, after first verifying the hours taken were in conformance with 5

the schedule, contractual provisions, and maintenance procedures. The aggregate maintenance credit 6

totaled 23,053 hours. 7

7. Wind Operating Programs 8

Wind generation from SCE’s PURPA projects is concentrated in two geographical areas: the 9

Tehachapi Wind Resource Area near Mojave and the San Gorgonio Wind Resource Area near Palm 10

Springs. During the record period, SCE administered PURPA contracts with 55 wind generation 11

projects with a total on-line capacity of 989 MW. SCE performs administrative activities unique to 12

wind generation to assure contract performance including: turbine inventory, real time wind monitoring, 13

a VAR monitoring program wind generation curtailments, and automatic recloser replacement. These 14

activities are explained in the following sections and provide an account of related events that occurred 15

during the Record Period. 16

a) Turbine Inventory 17

This activity consists of identifying the type, size, and quantity of installed wind turbine 18

generators at a project. Wind generation projects are modular in design, often having hundreds of 19

individual turbines spread over several miles of varying terrain that can be easily changed, added, or 20

removed. It is possible that the installed capacity and operating characteristics of a wind project can 21

change in a manner that may conflict with contract terms. SCE conducts periodic on-site surveys of 22

wind projects and obtains turbine inventory lists from the wind park operators for verification. SCE 23

performs these on-site surveys that result in updated inventory lists and verifies that these wind projects 24

are complying with their contract provisions. 25

-37-

b) Real-time Wind Monitoring System 1

Generation from wind turbines is inherently inconsistent as the energy in the wind varies 2

constantly. It can vary greatly over short time periods. Induction generators used in some wind turbines 3

can create voltage instability. Because of these factors, SCE’s system operators, transmission operators, 4

and SCE personnel must have access to timely data regarding wind conditions and wind generation. 5

Real-time data is essential for making control decisions concerning the switching of capacitors, 6

transformer taps, and the system configuration required to maintain acceptable voltage levels in light of 7

changing generation output. Meters installed at QF generators communicate 15-minute averages using 8

the NETCOM radio packet network. Because of the particular problems posed by the reactive loads and 9

rapid variations inherent in wind generation, the longer data interval (15 minutes instead of 1 minute) 10

was not completely satisfactory for grid operations. To provide sufficient near-real-time information, a 11

number of key nodes in the electrical system were identified and instrumented with devices (not meters) 12

that provide data to the operating centers every four seconds. 13

The 15-minute metering data is sent twice daily to an SCE contractor, who prepares a wind and 14

generation forecast. The data provides a method for regularly updating a forecast to improve forecast 15

accuracy. During the Record Period, SCE also used the data to monitor PURPA project compliance 16

with the VAR program, which is discussed in the following section. 17

c) VAR Program 18

The VAR program is designed to monitor capacitance at wind generation projects. During the 19

Record Period, the program monitored 36 projects with PURPA contracts that are directly connected to 20

the SCE electrical system for compliance with their contractual VAR requirements.27 The program does 21

not include a number of wind projects that are connected to the SCE system through a privately-owned 22

220 kV transmission line called the Sagebrush 220 kV line. The project also does not include wind 23

27 VAR stands for “volt-amperes reactive.” VAR represents the power consumed by a reactive load: i.e., when there is a

phase difference between the applied voltage and the current. It is a measure of the apparent power in alternating current transmission and distribution equipment. See, http://en.wikipedia.org, “Volt-amperes reactive.”

-38-

projects connected outside of SCE’s territory. Maintaining the minimum VAR requirements assists in 1

stabilizing the voltage on the sub-transmission system, thus improving system integrity. Voltage 2

instability is when the voltage level is plus or minus 5% outside of the normal SCE system level at the 3

project’s interconnection point.28 4

Under the VAR program, these projects are required to maintain their VAR compensation 5

capacitors so that the wind projects do not exceed their maximum consumption allowances. The VAR 6

monitoring program encourages these projects to keep their capacitor support in proper operating order, 7

thereby reducing the level of the VAR deficiency that, in past years, has caused grid instability. 8

During the Record Period, SCE required wind projects to limit their VAR demands as monitored 9

at the interconnection point. SCE monitors each project’s VAR compliance by reviewing the 15-minute 10

data. Non-compliant PURPA projects are curtailed prior to compliant PURPA projects in the event of 11

VAR-related system voltage instability. Of the 36 PURPA projects participating in this program at the 12

end of the Record Period, 15 were in compliance. The remaining 21 projects were non-compliant; see 13

Table IX-10 below. None of these non-compliant projects were curtailed because the system did not 14

experience voltage instability due to VAR deficiency. 15

28 Voltage is electric potential or potential difference expressed in volts. See, http://merriam-webster.com, “Voltage.”

-39-

Table IX-10

PURPA Non-Compliant VAR Projects January 1, 2012 Through December 31, 2012

d) Wind Curtailments 1

During the Record Period, wind curtailments were required to maintain and upgrade the 2

electrical system, to expand SCE’s transmission system (specifically for the Tehachapi Renewable 3

Transmission Project (TRTP)), to protect the Goldtown-Lancaster 66kV transmission line from overload 4

conditions, and to replace failed Automatic Reclosers. These situations are described in further detail 5

below. 6

(1) Supporting Maintenance and Upgrades of the Electrical System 7

The electrical systems in both the Tehachapi and San Gorgonio areas are being upgraded and 8

maintained due to the age of the system, system limitations, and technology improvements. 9

RAP ID Project

6004 FPL Energy Cabazon Wind, LLC

6031 EUI Management PH Inc.

6037 Tehachapi Power Purchase Contract Trust

6042 Wind Stream Operations, LLC (VG #4)

6051 Section 20 Trust

6052 NAWP Inc. [East Winds Proj]

6056 Edom Hills Project 1, LLC

6058 San Gorgonio Westwinds II, LLC

6087 Section 16-29 Trust (Altech III)

6088 Difwind Partners

6089 CTV Power Purchase Contract Trust

6092 Ridgetop Energy, LLC (II)

6094 Section 22 Trust [San Jacinto]

6095 Dutch Energy

6096 Westwind Trust

6111 Wind Stream Operations LLC (Northwind)

6112 Painted Hills Wind Developers

6213 BNY Western Trust Company

6234 Oak Creek Energy Systems Inc.

6236 Calwind Resources Inc. Unit 2

6366 Mogul Energy Partnership I, LLC

-40-

Maintenance activities include replacing equipment, inspecting the system, and performing equipment 1

testing and calibration. Upgrades performed on the system include building new transmission lines, 2

increasing transmission conductor size, installing new equipment, and reconfiguring the system. To 3

implement these system upgrades and to maintain the system, various transmission line and substation 4

outages were required. Due to these outages, curtailments of the wind projects in these areas were 5

necessary to perform the work and to maintain system stability. SCE’s RAP Contract Compliance 6

Group supported grid operations by notifying wind project operators of these outages through an 7

automated curtailment notification e-mail system called the Outage Notification System (ONS) and by 8

coordinating the outages. ONS serves two main purposes: to notify wind park operators via email of 9

upcoming outages that will cause curtailments and, if necessary, prorates the curtailments among the 10

impacted wind projects. 11

(2) The TRTP Project 12

TRTP consists of a series of new and updated electric transmission lines and substations that will 13

deliver electricity from new wind and solar projects in the Tehachapi/Mojave area to the CAISO grid 14

and increase the capability of the grid to distribute approximately 4,500 MW of new renewable power to 15

our customers. This project is a vital part of helping California meet its renewable energy goals. The 16

project involves 220 kV and 500 kV transmission line upgrades and the construction of new substations 17

between the Tehachapi Wind Resource Area in southern Kern County and Los Angeles County. 18

During construction, various transmission line and substation outages were required. Due to 19

these outages, the existing transmission facilities were limited, necessitating periodic curtailments for 20

the wind generators in the Tehachapi/Mojave area. 21

SCE’s RAP Contract Compliance Group coordinated with SCE’s TRTP Project Group and the 22

SCE’s Grid Control Center to match the needs of construction and the ability of the wind projects to 23

control output. Through ONS, SCE’s RAP Contract Compliance Group notified the wind projects of 24

curtailments and performed calculations of lost output that were then sent to the TRTP Project Group to 25

be used in making payments to certain wind operators, specifically those that are interconnected to the 26

Sagebrush 220 kV line and had made particular arrangements beforehand with SCE. 27

-41-

(3) The Goldtown-Lancaster 66 kV Transmission Line 1

In May 2008, SCE adopted an operating procedure (OP 68) to protect the Goldtown-Lancaster 2

66 kV transmission line from an overload condition in the event of a failure on the Cal Cement - 3

Antelope 66 kV line. The procedure limits the wind generation in the Tehachapi/Mojave area that is 4

interconnected to the 66 kV Antelope and Bailey systems to a level that will prevent the Goldtown-5

Lancaster line from exceeding its emergency rating. In July 2009, SCE reached an agreement with the 6

Terra-Gen’s Ridgetop I and Ridgetop II wind projects (RAP ID 6024 and 6092) in Tehachapi to provide 7

excess curtailment optionality (see discussion in B(2)c in this Chapter IX above). During the Record 8

Period, . These curtailments may no longer be 9

necessary after the Tehachapi generation is connected to the completed TRTP transmission line via the 10

East Kern Wind Resource Area (EKWRA) project. The EKWRA project will reconfigure the existing 11

66 kV system in the Tehachapi and Mojave areas and is estimated to be completed in 2014. The 12

reconfiguration includes moving all of the existing 66 kV lines in the area that interconnect to the 13

Antelope and Bailey 66 kV systems to connect them to the Windhub System, which was built as part of 14

the TRTP. 15

(4) Automatic Recloser Replacement 16

During the Record Period, three Automatic Reclosers (ARs) failed in the San Gorgonio Wind 17

Area. SCE’s RAP Contract Compliance Group coordinated the replacement of these ARs. 18

8. Insurance Verification 19

PURPA and CHP projects generally are required to obtain and maintain comprehensive general 20

liability insurance during the terms of their power purchase contracts. The WES system is used to 21

provide automated tracking of the insurance coverage. During the Record Period, 175 PURPA contracts 22

and 13 CHP contracts were subject to SCE’s insurance verification procedures, which may include 23

checking to ensure that these contracts have: 24

� Obtained the required insurance before their projects can be operated in parallel with the 25

SCE electrical system. 26

� Maintained insurance policies and insurance carriers that meet SCE’s requirements. 27

-42-

� Maintained adequate insurance coverage throughout the terms of their contracts. 1

During the Record period, SCE received certificates for 124 projects. 2

9. Forecasting and Scheduling Accuracy 3

Certain CHP contracts have provisions for evaluating the accuracy of project’s energy and/or 4

capacity forecast and assessing financial penalties associated with excessive forecast errors. To enforce 5

forecasting and scheduling accuracy requirements, two new compliance programs were instituted during 6

the Record Period: Mean Absolute Error (MAE) and Scheduling and Delivery Deviation (SDD) 7

Adjustments. 8

In the MAE program, a monthly mean absolute error between a project’s day-ahead forecast and 9

actual production is quantified and compared to a threshold. Exceeding the error threshold can result in 10

a forecasting penalty, and multiple non-compliances can trigger a temporary de-rating of the project’s 11

firm contract capacity. During the Record Period, of the three CHP projects subject to the MAE 12

program, one project, 13

14

The purpose of SDD Energy Adjustments is to mitigate, for SCE and the project, any financial 15

gains or losses due to excessive deviation of metered energy deliveries from the project’s hour-ahead 16

schedule. SDD Adjustments are based on differences between real-time energy prices and contract 17

energy prices. Additionally, an administrative charge, based on CAISO’s grid management charge for 18

uninstructed deviations, is assessed and charged to the project for any scheduling deviation outside of 19

the performance tolerance band. During the Record Period, four CHP projects incurred administrative 20

charges totaling $5,865 for generating outside of the SDD performance tolerance band. 21

-43-

D. Affiliate Contract Information 1

This section is provided in accordance with D.90-09-088, Ordering Paragraph (OP) 4, which 2

requires SCE to provide the following information in annual reviews regarding its purchases from 3

PURPA / CHP29 projects in which its affiliate, Edison Mission Group, holds an interest: 4

1. Percent of affiliate ownership. 5

2. Name of the affiliate. 6

3. Date ownership was acquired. 7

4. Energy production (in kWh) by time period by month. 8

5. Energy and capacity payments by time period by month. 9

6. On-peak capacity factor by month. 10

7. Capacity bonus payments by month. 11

8. Scheduled downtime by month. 12

9. Unscheduled outages by month with an explanation of the outage cause.30 13

Table IX-11 provides the information requested in items 1 through 3, Table IX-12 and Table IX-13 14

(a) - (c) provide the information requested in items 4 through 7,31 and Table IX-14 provides the 15

information requested in item 8. 16

29 While these projects entered the Record Period on extensions of Legacy Agreements, and thus were PURPA projects,

they have all signed Transition PPAs which are non-PURPA. 30 See D.90-09-088, OP 4. 31 For purposes of these tables, “on-peak capacity factor” in any month is calculated as the ratio of (a) the on-peak kWh in

that month to (b) the product of the project’s firm contract capacity and the number of on-peak hours in that same month.

-44-

Table IX-11 Affiliate PURPA / CHP Projects and Ownership


Table IX-12 Summary of Production by and Payments to Affiliate PURPA Projects

January 1, 2012 Through December 31, 2012.

RAP ID Project Name % Mission Ownership

Mission Entity Date Acquired

2053 Watson Cogeneration Co. 49% Camino Energy Co. September 10, 1986

2058 Sycamore Cogeneration Co. 50% Western Sierra Energy Co. February 20, 1986

2801 Kern River Cogeneration Co. 50% Southern Sierra Energy Co. June 23, 1983

RAP ID

Project Name Total KWH Total Energy Payments ($)

Total Capacity Payments ($)

Total Bonus

Payments ($)

Total Payment ($)

2053 Watson Cogeneration Co. 2,253,596,760 $71,049,773.95 $31,259,614.04 $0.00 $102,309,387.99

2058 Sycamore Cogeneration Co. 1,429,583,096 $42,317,594.49 $25,090,070.26 $0.00 $67,407,664.75

*2801 Kern River Cogeneration Co. 1,328,098,982 $38,134,696.27 $26,581,461.96 $0.00 $64,716,158.23

*See Table IX-13(c) for dispatch, startup, and CAISO charges breakdown

Produc

Project N

-45-

ction by and PJanuary 1, 2

Name: Watson

Table IX-13(aPayments to Aff2012 Through Cogeneration

a) ffiliate PURPA

December 31,Company (RA

A Projects ,

AP ID 2053)

-46-

Section 1: This section reflects kWh generated, paid for and reported during this Record Period.

: : : BILLING PERIOD ON-PEAK MID-PEAK OFF-PEAK S/OFF PEAK : ON-PEAK MID-PEAK OFF-PEAK S/OFF PEAK : ON-PEAK MID-PEAK OFF-PEAK S/OFF PEAK : BONUS :

: : : :: : : :

1/1/2012 2/1/2012 0 45,709,263 46,949,604 32,081,032 : $0.00 $1,841,700.21 $1,476,320.72 $842,875.06 : $0.00 $342,624.82 $20,832.31 $13,879.98 : $0.00 :2/1/2012 3/1/2012 0 38,555,138 40,769,813 26,176,485 : $0.00 $1,301,431.07 $1,091,771.85 $592,159.55 : $0.00 $306,989.16 $19,753.67 $12,318.86 : $0.00 :3/1/2012 4/1/2012 0 38,690,383 41,095,526 26,818,580 : $0.00 $1,181,769.04 $995,548.24 $570,092.34 : $0.00 $358,252.25 $24,171.43 $14,884.10 : $0.00 :4/1/2012 5/1/2012 0 43,285,644 42,568,306 29,198,009 : $0.00 $1,217,053.45 $963,043.35 $575,709.79 : $0.00 $332,993.96 $20,704.23 $13,503.95 : $0.00 :5/1/2012 6/1/2012 0 38,608,411 40,474,477 26,772,692 : $0.00 $1,068,239.30 $859,274.93 $488,570.17 : $0.00 $314,763.59 $19,610.41 $12,382.21 : $0.00 :6/1/2012 7/1/2012 30,865,311 30,453,148 64,319,053 0 : $1,152,818.44 $831,318.26 $1,510,346.50 $0.00 : $4,944,307.20 $574,236.86 $10,954.51 $0.00 : $0.00 :7/1/2012 8/1/2012 30,567,690 29,978,860 65,832,178 0 : $1,233,527.65 $918,058.04 $1,660,690.55 $0.00 : $4,944,307.20 $565,290.20 $10,585.01 $0.00 : $0.00 :8/1/2012 9/1/2012 33,674,120 32,605,337 60,065,479 0 : $1,315,444.04 $971,096.46 $1,571,585.27 $0.00 : $4,944,307.20 $561,355.73 $10,383.87 $0.00 : $0.00 :9/1/2012 10/1/2012 28,152,526 27,490,153 67,470,276 0 : $910,470.12 $794,621.65 $1,471,209.81 $0.00 : $4,944,307.20 $572,928.22 $10,698.74 $0.00 : $0.00 :

10/1/2012 11/1/2012 0 51,302,722 45,953,492 32,785,888 : $0.00 $1,871,848.35 $1,335,367.68 $823,807.31 : $0.00 $408,493.80 $25,713.52 $16,286.47 : $0.00 :11/1/2012 12/1/2012 0 41,233,847 45,403,981 29,466,562 : $0.00 $1,765,183.60 $1,550,675.53 $910,414.79 : $0.00 $324,531.96 $20,506.05 $13,101.06 : $0.00 :12/1/2012 1/1/2013 0 41,246,447 49,864,738 33,097,925 : $0.00 $1,871,479.25 $1,808,848.26 $973,223.86 : $0.00 $324,630.19 $21,160.39 $14,319.95 : $0.00 :

: : : :TOTALS: 123,259,647 459,159,353 610,766,923 236,397,173 : $4,612,260.25 $15,633,798.68 $16,294,682.69 $5,776,852.87 : $19,777,228.80 $4,987,090.74 $215,074.14 $110,676.58 : $0.00 :

TOTAL ENERGY $ $42,317,594.49 TOTAL CAPACITY $: $25,090,070.26 TOTAL BONUS $: $0.00

TOTAL KWH: 1,429,583,096 TOTAL ENERGY & CAPACITY $: $67,407,664.75

Section 2: This section reflects adjustments in kWh generated and payments applicable to prior periods but made during this Record Period.

Dollars KWhTOTAL CAPACITY CORRECTIONS TO PRIOR PERIODS $0TOTAL ENERGY CORRECTIONS TO PRIOR PERIODS $25,140TOTAL INTEREST CALCULATED FOR PRIOR PERIOD CORRE $3,250

$28,390 -

KWH ($) ($)

ENERGY CAPACITYPAYMENTS PAYMENTS

Table IX-13(b) Production by and Payments to Affiliate PURPA Projects

January 1, 2012 Through December 31 Project Name: Sycamore Cogeneration Company (RAP ID 2058)

1

2

3

4

5

6

7

8

9

10

11

12

1

Produ

Project Na

-47-

uction by and PJanuary 1, 20

ame: Kern Riv

Table IXPayments to Af012 Through Dver Cogenerati

X-13(c) Affiliate PURPADecember 31, 2ion Company (

PA Projects 2012 (RAP ID 28011)

-48-

Table IX-14 provides the scheduled maintenance hours by month that SCE allowed for each 1

affiliate PURPA / CHP project (in reference to item 8). 2

Table IX-14 Allowed Affiliate Maintenance Hours

January 1, 2012 Through December 31, 2012 Month RAP ID

2053 RAP ID

2058 RAP ID

2801 Total

January 124 0 0 124

February 79 28 0 107

March 96 648 0 744

April 106 80 0 186

May 7 0 0 7

June 0 0 0 0

July 7 0 0 7

August 0 0 0 0

September 0 0 0 0

October 270 396 0 666

November 21 0 0 21

December 14 0 13 13

Total 710 1152 13 1875

Finally, item 9 is partially addressed through the listing of uncontrollable force claims in Table 3

IX-5 above. Additionally, SCE does not require PURPA contract counterparties to provide data on 4

unscheduled outages. As a result, SCE does not keep records of unscheduled PURPA project outages 5

other than those outages that may ultimately affect the project’s compliance with its capacity 6

performance requirements. 7

In addition to the nine items discussed above, OP 4 requires SCE to submit the following for 8

each affiliate PURPA / CHP contract: “An accounting of steps SCE has taken or considered taking to 9

recover overpayments or damages from its affiliates that may have breached their contracts, and all other 10

steps taken or considered in administering PURPA contracts with affiliates.”32 SCE reports here on the 11

following items in response to this OP. 12

32 D.90-09-088, OP 4.

-49-

All affiliates began the Record Period on “Extension Agreements.” In D.07-09-040, the 1

Commission order SCE to extend the non-price terms of its expiring PURPA contracts if the project 2

counterparties so desired. Pursuant to Section 11.2.1 of the CHP Settlement, “extensions of Legacy 3

CHP PPAs ordered by the Commission pursuant to D.07-09-040 shall remain in effect until the date the 4

Seller commences power deliveries under a Subsequent PPA pursuant to this Settlement”.33 Subsequent 5

PPAs for each affiliate have been executed, as explained further below. 6

1. Watson Cogeneration Company (RAP ID 2053) 7

On December 19, 1984, Watson Cogeneration Company (RAP ID 2053) executed a PPA with 8

SCE. This agreement terminated on December 31, 2007. Watson elected an extension and, accordingly, 9

its PPA was extended. 10

On January 13, 2012, SCE staff met with Watson representatives to discuss the execution of a 11

Transition Standard Contract for Existing Qualifying Cogeneration Facilities (“Transition PPA”), 12

pursuant to D.07-09-040 and D.10-12-035, and to begin negotiation of an amendment to the Transition 13

PPA to facilitate the purchase and sale of Additional Dispatchable Capacity, pursuant to Section 3.4.1.2 14

of the CHP Program Settlement Agreement Term Sheet. 15

SCE and Watson executed a Transition PPA on June 5, 2012 (the “Watson Transition PPA”). 16

On August 3, 2012, SCE filed Advice Letter 2763-E, seeking approval of the Watson Transition PPA. 17

On December 20, 2012, the Commission approved the Watson Transition PPA, without modification, 18

via Resolution E-4537. Additionally, the agreement was filed for FERC approval on August 3, 2012 19

(Docket No. ER12-2397). SCE approximates the total payments to Watson from January 2013 to the 20

end of the Transition Period under the Transition PPA to be $319 million. During this period, the Firm 21

Capacity payments are expected to be $14.9 million less than those SCE would have incurred under a 22

continuation of the Legacy PPA. 23

33 CHP Settlement Term Sheet at page 52. http://asset.sce.com/Documents/Environment%20-

%20Renewable%20Energy/CHP_Program_Settlement_Term_Sheet.pdf

-50-

At the end of the Record Period, SCE and Watson were still in negotiations over the purchase 1

and sale of Additional Dispatchable Capacity. 2

2. Sycamore Cogeneration Company (RAP ID 2058) and Kern River Cogeneration 3

Company (RAP ID 2801) 4

Sycamore successfully participated in SCE’s first CHP RFO and executed a CHP RFO PPA with 5

SCE on July 2, 2012. The agreement was filed for approval by the CPUC on October 1, 2012 (AL 6

2784-E) and is awaiting approval. The agreement was filed for FERC approval on October 16, 2012 7

(Docket No. ER13-133) and was approved on February 8, 2013. If approved by the CPUC, Sycamore 8

will commence deliveries under the RFO PPA on January 1, 2014. 9

KRCC initially participated in SCE’s first CHP RFO, but withdrew prior to determination of the 10

short list. 11

Also during 2012, pursuant to the CHP Settlement, Sycamore / KRCC and SCE engaged in 12

extensive negotiations around a Transition Agreement to replace Sycamore / KRCC’s Legacy PPAs and 13

extension agreements. Although the original deadline to execute a Transition Agreement or face 14

termination of the extension agreements was March 22, 2012, SCE and Sycamore / KRCC requested, 15

and the CPUC granted, an extension of the deadline to June 1, 2012. Subsequently, Sycamore / KRCC 16

requested, and the CPUC granted, multiple extensions of the deadline to execute a Transition Agreement 17

with the final date being October 15, 2012. 18

Unable to reach agreement on pricing for the Transition Agreement, SCE and Sycamore / KRCC 19

participated in mediation led by the CPUC on September 12, 2012. The mediation led to an agreement 20

on pricing, and SCE executed Transition Agreements with both KRCC and Sycamore on October 15, 21

2012. The KRCC Transition Agreement was filed for approval by the CPUC (AL 2825-E) and FERC 22

(Docket No. ER13-559) on December 14, 2012 and is awaiting approval. Likewise, the Sycamore 23

Transition Agreement was filed for approval by the CPUC (AL 2825-E) and FERC (Docket No. ER13-24

558) on December 14, 2012 and is awaiting approval. 25

-51-

E. PURPA and CHP Contract Payment Process 1

SCE applies a set of four policies to ensure that existing and any new PURPA or CHP contracts 2

are paid accurately and on a timely basis, and that documentation and updates to contract terms are 3

placed into WES. These policies are: 4

1. Pay projects according to the terms and conditions of their contracts, as interpreted in 5

light of relevant Commission decisions, orders, pertinent industry practice, and internal 6

SCE controls, including those controls necessary to comply with the Sarbanes-Oxley 7

legislation. 8

2. Make payments in a timely manner according to the terms and conditions of the 9

contracts. 10

3. Subject to timely notification of errors by the PURPA or CHP project and in conformity 11

with contractual terms, correct any calculation errors for a time period up to that 12

permitted under the contract and applicable statute of limitations. 13

4. Promptly investigate the facts relating to disputes. If adjustments are warranted, carry 14

them out in a timely manner. 15

The sections below discuss the procedures, guidelines, and processes regarding the monitoring, 16

validation, and calculation of PURPA and CHP contract settlements. These procedures relate to 17

administering performance bonus provisions, obtaining data for projects located outside of SCE’s 18

service area, administering the loss factors, and applying the correct energy and capacity rate 19

calculations. 20

1. Performance Bonus 21

Many firm capacity PURPA contracts contain provisions that enable the projects to earn capacity 22

bonus payments to encourage on-peak production during summer months. Projects are eligible to 23

receive winter bonus payments if they meet specified summer on-peak contract performance 24

requirements. SCE ensures that only the firm capacity PURPA contracts that have met monthly and 25

seasonal contractual requirements receive a bonus payment. 26

-52-

2. OST Projects 1

As mentioned above, a number of SCE’s PURPA and CHP projects are located outside of SCE’s 2

service territory (e.g., the IID and PG&E service territories), where energy is typically delivered by the 3

local utility to SCE over that utility’s interties with SCE. SCE receives the quantity of energy 4

represented by, and pays the PURPA and CHP projects based upon, hour-by-hour energy delivery 5

schedules from the delivering utility. Each monthly delivered quantity is validated against the delivered 6

quantities from which the payment is calculated. 7

3. Line Loss Factor 8

During the Record Period, PURPA and CHP projects that received Commission-approved SRAC 9

prices for their energy deliveries (and did not execute a Legacy Agreement providing for a line loss 10

factor of 1.00)34 continued to have the line loss factor methodology specified in D.01-01-007 applied to 11

their energy payment calculations. The line loss factors for a particular PURPA or CHP contract include 12

the project’s distribution loss factor (DLF) and transmission loss factor (TLF), and, in some cases, the 13

transformer loss factor (unrelated to D.01-01-007). 14

Since the April 1, 2009 “go live” of the Market Redesign and Technology Upgrade (“MRTU”), 15

the CAISO discontinued posting generator meter multipliers (GMM) / tie meter multipliers (TMM) that 16

are a component of the TLF calculation. Starting in May 2009, SCE replicated the April through 17

December 2008 GMM/TMM data to use in the calculations for the same monthly settlement periods in 18

2009. 19

4. Energy and Capacity Rate Calculations 20

In 2006, the Commission issued Resolution E-4026, which approved fixed price agreements to 21

61 PURPA projects. These agreements became effective May 1, 2007, and are discussed in SCE’s 2007 22

34 The five-year renewable fixed rate agreements that SCE executed provide for an agreed-upon loss adjustment factor of

1.00 for the five-year pricing period in the agreements. See Section A.1 of the PURPA chapter of SCE’s 2007 ERRA filing (A.07-04-001) indicating this agreed-upon loss adjustment factor of 1.00 during the five-year period in those agreements.

-53-

ERRA filing.35 In short, these agreements provide for a new fixed energy price of $0.0615 / kWh, 1

which was escalated at 1% per year for a five-year period beginning May 1, 2007. This period expired 2

on May 1, 2012. In anticipation of this expiration, in April and October of 2011 SCE held a Fixed Price 3

RFO. QFs participating in the RFOs were required to have existing PURPA PPAs whose term will 4

cover the fixed price period and are with non-gas fired QF resources. An agreement would be awarded 5

to bidders requesting fixed prices at or below SCE’s forward curve of SRAC pricing. The first RFO 6

resulted in three QFs signing Fixed Price Agreements that were approved by the Commission in 7

Resolution E-4443 on December 1, 2011. The three Agreements’ fixed prices are $0.0540 / kWh, 8

$0.054324 / kWh, and $0.0550 / kWh. All three Agreements were effective May 1, 2012 and have 9

varying expiration dates in 2014. The second Fixed Price RFO resulted in eight QFs signing Fixed Price 10

Agreements that were approved by the Commission in Resolution E-4490 on June 21, 2012. These 11

Agreements are effective January 1, 2013 through December 31, 2013. The fixed prices that are in lieu 12

of SRAC are as follows: 13

Number of QFs Fixed Price (per kWh)

3 $0.04798 + LA 1 $0.04802 + LA 1 $0.04811 + LA 3 $0.04817 + LA

Upon expiration of these Fixed Price Agreements, the fixed price will revert to SRAC. 14

All other renewable PURPA projects that had Energy Crisis-related fixed energy rates reverted 15

to a short run avoided cost (SRAC) energy price on or before May 1, 2007. On August 1, 2009, the 16

Commission implemented Resolution E-4246, which finalized a new market index formula (MIF) that 17

changed how SRAC energy pricing is calculated and established new as-available capacity rates.36 18

35 A.07-04-005, Ex. 2, pp. 46-47. 36 Resolution E-4246 affects all PURPA contracts, both renewable and cogeneration, that are paid SRAC pricing for energy

and as-available capacity.

-54-

The new SRAC, effective January 1, 2012, includes an adder called the Hourly Location 1

Adjustment Factor (LA). 37 The LA was implemented to replace the GMM (Generation Meter 2

Multiplier); after MRTU “go-live” in April 2009, CAISO discontinued publishing the GMMs because it 3

had converted to a Nodal Market. The LA is equal to LMP(QF) minus LMP(Trading Hub), where LMP(QF) 4

equals the hourly day-ahead location marginal price (LMP) at the point of interconnection with CAISO 5

grid associated with the QF generating facility, and LMP(TradingHub) is the hourly LMP of the trading hub 6

where the generating facility is located (e.g., SP15). The LA calculation is performed hourly. 7

The LA applies to the various PURPA and CHP agreements as follows: 8 � Legacy Amendments 9

o Option A: Subject to LA 10

o Option B: Non-renewable projects are subject to LA, renewable projects 11

are not 12

o Option C1: Not subject to LA (fully negotiated pricing) 13

o Options C2 and C3: Subject to LA 14

� Transition PPA: Subject to LA 15

� CHP RFO PPA: Subject to LA 16

� QF SOC: Subject to LA 17

� AB 1613 Agreements: Not subject to LA 18

37 D.10-12-035

55

X. 1

RENEWABLES PORTFOLIO STANDARD CONTRACT ADMINISTRATION COSTS 2

SCE originates power purchase agreements to implement California’s Renewables Portfolio 3

Standard (RPS), which became effective January 1, 2003.38 The RPS legislation required that certain 4

load-serving entities (LSEs), including Investor Owned Utilities (IOUs),39 increase their procurement 5

from eligible renewable energy resources (ERRs), as defined in the legislation, by at least 1% of their 6

annual sales per year, so that 20% of their retail sales are served by generation from ERRs in 2010.40 In 7

2011, the Legislature expanded the RPS to 33% when it passed Senate Bill X 1 2.41 8

A. Introduction to RPS Contract Administration 9

Commission Resolutions approving RPS contracts typically provide for the recovery of all 10

payments made pursuant to those contracts, subject to the Commission’s review of the reasonableness of 11

SCE’s contract administration. In Decision (D.) 02-10-062, the Commission established the ERRA to 12

track utility retained generation, procurement activities, and purchased power expenses. These expenses 13

include power purchased pursuant to the RPS contracts discussed in this chapter. 14

During the Record Period, SCE purchased 8.031 billion kWh42 from 49 RPS projects, and 15

recorded RPS payments of $692 million. In the following discussion, SCE sets forth its recorded RPS 16

contract-related expenses, describes its RPS contract development and administration activities during 17

the Record Period, and demonstrates that such activities were reasonable.43 18

38 See Public Utilities Code § 399.11, et. seq. 39 California’s IOUs are SCE, Pacific Gas & Electric (PG&E) and San Diego Gas & Electric (SDG&E). 40 See Public Utilities Code § 399.15, et. seq. 41 See http://www.leginfo.ca.gov/pub/11-12/bill/sen/sb_0001-0050/sbx1_2_bill_20110412_chaptered.pdf . Additionally,

this bill eliminated the 1% per year requirement in the previous RPS legislation. 42 Purchases in billion kWh from RPS contracts by month were as follows:

Billion kWh Delivered Jan. Feb. Mar. Apr. May June July Aug. Sept. Oct. Nov. Dec. Total

1/01/2012 – 12/31/2012 8.031 43 Two summary documents accompany this chapter as Appendices X-A and X-B. Appendix X-A, entitled “List of RPS

Projects,” lists each RPS project and the corresponding Commission application for approval or resolution that found the (Continued)

56

SCE executes power purchase agreements (referred to as RPS contracts or PPAs) with renewable 1

generators through competitive solicitations, bilateral discussions, standard contracts, and feed-in tariffs. 2

Pursuant to Assembly Bill 1969 and Senate Bill 380, SCE administers a feed-in tariff for eligible 3

renewables 1.5 MW and less under the California Renewable Energy Small Tariff (CREST). SCE 4

executed 137 contracts for a total of 185.391 MW under the CREST tariff during the Record Period. 5

Pursuant to the Governor’s Executive Order S-06-06,44 SCE also voluntarily developed a 6

standard biomass program for eligible projects of 20 MW and less. This program was then made 7

available to all renewable generators through Renewable Standard Contracts (RSC) for generators 5 8

MW and less (RSC5) and 20 MW and less (RSC20). Any eligible renewable generator could access 9

these RSCs online and execute the agreement with SCE. 10

During the 2010 Record Period, in response to the market, SCE changed the structure of this 11

program and modeled it after SCE’s all-source request for offers (RFOs) with reverse auction pricing 12

instead of offering a fixed price at the Market Price Referent (MPR). In D.10-12-048, issued on 13

December 17, 2010, the Commission adopted a new procurement process called the Renewable Auction 14

Mechanism (RAM) to procure renewable energy from projects 20 MW or less that are RPS-eligible, 15

replacing SCE’s RSC program. D.10-12-048 ordered SCE, PG&E, and SDG&E to implement the 16

RAM, procuring a total of 1,000 MW allocated across the utilities over a two-year period through 17

competitive auctions using standard non-negotiable contracts.45 18

Continued from the previous page RPS contract reasonable as to formation. Appendix X-B, entitled “ERRA RPS Payments Summary Table,” sets forth payment and production figures for each RPS project from which SCE purchased power during the Record Period.

44 Signed April 25, 2006, the executive order established a 20% biomass target within the 20% state RPS target.

45 The Commission further clarified details of the RAM program in Resolution E-4414, issued August 22, 2011, Resolution E-4489, issued April 19, 2012 and Resolution E-4546, issued November 8, 2012.

57

Additionally, SCE administers the Solar Photovoltaic Program (SPVP). Under SPVP RFOs, 1

SCE will conduct solicitations for 125 MW of solar photovoltaic installations over a 5-year period, with 2

primarily rooftop projects in the 1-2 MW range.46 3

Projects that are in development or generate power for sale under RPS contracts are discussed in 4

this chapter and are referred to as “RPS projects.”47 Additionally, there are many renewable projects 5

selling electric power to SCE which have maintained status as Qualifying Facilities and are delivering 6

renewable energy to SCE under a PURPA contract. As such, they are covered in Chapter IX. 7

B. Contract Management 8

This section provides information on all activities related to the management of RPS contracts, 9

including contract development, amendments, assignments, securities received, contract capacity 10

demonstration, measurement of energy deliveries, terminations, active monitoring of contracts to ensure 11

the project output qualifies under requirements of the RPS, and activities related to management of 12

projects in the Western Renewable Energy Generation Information System (WREGIS).48 13

1. Contract Development 14

During the Record Period, SCE entered into 162 new RPS contracts. 137 of these contracts, for 15

a total of 185.391 MW, are CREST contracts, 13 contracts for 164 MW were signed pursuant to RAM, 16

and 7 contracts totaling 9.5 MW were signed under SPVP. Additionally, SCE executed two contracts, 17

totaling 143 MW, for sales of bundled RPS energy and green attributes. Table X-15 below shows the 18

46 On February 11, 2011, SCE filed a Petition for Modification of the SPVP, requesting that the Commission increase the

competitive solicitation portion of the SPVP from 250 MW to 375 MW, with 125 MW administered under the original SPVP-RFO parameters set forth in D.09-06-049 and Resolution E-4299 and 250 MW administered under revised parameters. On January 16, 2012, the Commission issued a Decision partially granting SCE’s Petition. The Decision modifies the SPVP to no more than 125 MW each of IPP procurement and utility development, with the amount of ground-mounted facilities increased to 20% (25 MW). The 250 MW cut from the original capacity cap were moved to the RAM program (as 200 MW AC).

47 As explained in Chapter IX, SCE uses a numbering convention called “RAP ID” (Renewable and Alternative Power Identification) to identify contracts by technology, where the 1000 series refers to biomass, the 3000 series refers to geothermal, the 4000 series refers to small hydro, the 5000 series to solar, and the 6000 series to wind. Formerly, these were identified as “QFID” or Qualifying Facilities Identification.

48 Throughout this section, any undefined, capitalized terms have the meaning set forth in the relevant RPS project contract.

58

contract identification number (RAP ID), project name, contract capacity (including information 1

regarding any expansion options), type of contract, the execution date of these contracts, and the 2

approval status. 3

Table X-15 RPS New Contracts Executed


Project Initial Nameplate Contract

Capacity and Expansion

Option (MW)

Contract Type

Executed Date Advice Letter or CPUC Resolution and Date

4202 Bishop Tungsten Development, LLC 0.25 CREST July 20, 2012 N/A

4206 Isabella Fish Flow Hydroelectric Project LLC 0.956 CREST July 20, 2012 N/A

4207 Monte Vista Water District 0.865 CREST July 20, 2012 N/A

4208 Lower Tule River Irrigation District 1.5 CREST July 5, 2012 N/A

4209 White Mountain Ranch, LLC 0.29 CREST July 5, 2012 N/A

4210 Calleguas MWD - Conejos 0.55 CREST July 20, 2012 N/A

5508 Adelanto 10, LLC 1.5 CREST August 1, 2012 N/A

5509 Newberry Solar 1, LLC 1.5 CREST June 30, 2012 N/A

5520 Treen Solar 1, LLC 1 CREST January 26, 2012 N/A

5521 Treen Solar 2, LLC 1 CREST January 26, 2012 N/A

5522 Annie Power, LLC 1.5 CREST January 26, 2012 N/A

5523 JRam Solar 1, LLC 1.5 CREST January 26, 2012 N/A

5524 JRam Solar 2, LLC 1.5 CREST January 26, 2012 N/A

5525 JRam Solar 3, LLC 1 CREST January 26, 2012 N/A

5526 Ayden Power, LLC 1.5 CREST January 26, 2012 N/A

5527 CSC Solar, LLC 1.5 CREST January 26, 2012 N/A

5528 CSC Solar I, LLC 1.5 CREST January 26, 2012 N/A

5529 CSC Solar II, LLC 1 CREST January 26, 2012 N/A

5530 Erika Solar, LLC 1.5 CREST January 26, 2012 N/A

5531 Carly Solar, LLC 1 CREST January 26, 2012 N/A

5532 Goodbar Solar 1, LLC 1.5 CREST January 26, 2012 N/A

5533 DT Solar 1, LLC 1.5 CREST January 26, 2012 N/A

5534 DT Solar 2, LLC 1.5 CREST January 26, 2012 N/A

5535 DT Solar 3, LLC 1 CREST January 26, 2012 N/A

5536 Sandra Energy, LLC 1.5 CREST January 26, 2012 N/A

59

5537 Abby Power, LLC 1.5 CREST January 26, 2012 N/A

5538 Cami Solar, LLC 1.5 CREST February 1, 2012 N/A

5539 Dreamer Solar, LLC 1.5 CREST February 1, 2012 N/A

5540 Josh Energy, LLC 1.5 CREST January 26, 2012 N/A

5541 Drew Energy, LLC 1 CREST January 26, 2012 N/A

5542 Amy Solar, LLC 1.5 CREST January 26, 2012 N/A

5543 Rachel Energy, LLC 1.5 CREST January 26, 2012 N/A

5544 MJ Power, LLC 1.5 CREST January 26, 2012 N/A

5545 Kell Solar 1, LLC 1 CREST January 26, 2012 N/A

5546 Kell Solar 2, LLC 1 CREST January 26, 2012 N/A

5547 Leolani Solar 1, LLC 1.5 CREST January 26, 2012 N/A

5548 Leolani Solar 2, LLC 1 CREST January 26, 2012 N/A

5549 Voyager Solar 1, LLC 1.5 CREST February 1, 2012 N/A



5552 Niner Energy 1, LLC 1.5 CREST January 26, 2012 N/A

5553 Niner Energy 2, LLC 1.5 CREST January 26, 2012 N/A

5554 Niner Energy 3, LLC 1 CREST January 26, 2012 N/A

5555 Lola Energy 1, LLC 1 CREST January 26, 2012 N/A

5556 Lola Energy 2, LLC 1 CREST January 26, 2012 N/A

5557 D2 Solar 1, LLC 1.5 CREST January 26, 2012 N/A

5558 D2 Solar 2, LLC 1.5 CREST January 26, 2012 N/A

5559 Becca Solar, LLC 1.5 CREST January 26, 2012 N/A

5560 Toro Power 1, LLC 1.5 CREST January 26, 2012 N/A

5561 Toro Power 2, LLC 1 CREST January 26, 2012 N/A

5562 Lancaster Solar 5 LLC 1.5 CREST January 16, 2012 N/A

5563 Lancaster Solar 4 LLC 1.5 CREST January 16, 2012 N/A

5564 Coronus Herperia West 1, LLC 1.2 CREST March 19, 2012 N/A

5565 Adelanto Greenworks D2, LLC 1.5 CREST June 6, 2012 N/A

5570 Summer Solar C2, LLC 1.5 CREST June 6, 2012 N/A

5571 Summer Solar D2, LLC 1.5 CREST June 6, 2012 N/A

5572 Summer Solar A2 1.5 CREST June 6, 2012 N/A

5573 Summer Solar B2, LLC 1.5 CREST June 6, 2012 N/A

5574 Rodeo Solar C2, LLC 1.5 CREST June 6, 2012 N/A

5575 Rodeo Solar B2, LLC 1.5 CREST June 6, 2012 N/A

5576 Rodeo Solar A2, LLC 1.5 CREST June 6, 2012 N/A

5577 Central Antelope Dry Ranch B2, LLC 1.5 CREST June 6, 2012 N/A

60

5578 Rodeo Solar D2, LLC 1.5 CREST June 6, 2012 N/A

5579 Summer Solar E2, LLC 1.5 CREST June 6, 2012 N/A

5580 Lancaster Del Sur Ranch C2, LLC 1.5 CREST June 6, 2012 N/A

5581 Summer Solar F2, LLC 1.5 CREST June 6, 2012 N/A

5582 Summer Solar G2, LLC 1.5 CREST June 6, 2012 N/A

5583 Summer Solar H2, LLC 1.5 CREST June 6, 2012 N/A

5584 Adelanto Greenworks C2, LLC 1.5 CREST June 6, 2012 N/A

5585 Expressway Solar C2, LLC 1.5 CREST June 6, 2012 N/A

5586 Victor Mesa Linda B2 1.5 CREST July 20, 2012 N/A

5587 ImMODO California 2, LLC (Exeter 1) 1 CREST July 20, 2012 N/A

5588 ImMODO California 2, LLC (Exeter 2) 1 CREST July 20, 2012 N/A

5589 ImMODO California 2, LLC (Exeter 3) 1.5 CREST July 20, 2012 N/A

5590 ImMODO California 2, LLC (Lindsay 1) 1.5 CREST July 20, 2012 N/A

5591 ImMODO California 2, LLC (Lindsay 3) 1.5 CREST July 20, 2012 N/A

5592 ImMODO California 2, LLC (Lindsay 4) 1 CREST July 20, 2012 N/A

5593 ImMODO California 2, LLC (Seville 1) 1.5 CREST July 20, 2012 N/A




5597 ImMODO California 2, LLC (Ivanhoe 1) 1.5 CREST July 20, 2012 N/A



5600 ImMODO California 2, LLC (Porterville 1) 1 CREST July 20, 2012 N/A

5601 ImMODO California 2, LLC (Porterville 2) 1 CREST July 20, 2012 N/A

5602 ImMODO California 2, LLC (Porterville 5) 1.5 CREST July 20, 2012 N/A

5603 ImMODO California 2, LLC (Tulare 1) 1.5 CREST July 20, 2012 N/A

5604 ImMODO California 2, LLC (Tulare 2) 1.5 CREST July 20, 2012 N/A

5605 Ever CT Solar Farm, LLC Site 1A 1 CREST July 20, 2012 N/A

5606 Ever CT Solar Farm, LLC Site 1B 1 CREST July 20, 2012 N/A

5607 Ever CT Solar Farm, LLC Site 2A 1.5 CREST July 20, 2012 N/A

5609 Ever CT Solar Farm, LLC 1 CREST July 20, 2012 N/A

61

Site 2B

5610 Ever CT Solar Farm, LLC Site 2C 1 CREST July 20, 2012 N/A

5611 Victor Mesa Linda D2 1.5 CREST July 20, 2012 N/A

5612 Victor Mesa Linda E2 1.5 CREST July 20, 2012 N/A

5613 East Valley Greenworks C 1.5 CREST July 20, 2012 N/A

5614 East Valley Greenworks D 1.5 CREST July 20, 2012 N/A

5615 East Valley Greenworks E 1.5 CREST July 20, 2012 N/A

5616 Victor Mesa Linda C2 1.5 CREST July 20, 2012 N/A

5618 Marinos Ventures LLC 0.28 CREST August 30, 2012 N/A

5619 ImMODO California 2 LLC (Farmersville 1) 1.5 CREST August 30, 2012 N/A



5632 SP Indigo Ranch A2, LLC 1.5 CREST October 5, 2012 N/A

5633 Coronus 29-Palms North 1 LLC 1.5 CREST August 30, 2012 N/A


5635 Coronus Hesperia West 2 LLC 1.5 CREST August 30, 2012 N/A

5636 Coronus Yucca Valley East 1 LLC 1.5 CREST August 30, 2012 N/A

5637 Coronus Yucca Valley East 2 LLC 1.5 CREST August 30, 2012 N/A


5645 ImMODO California 2 LLC (Porterville 6) 1.5 CREST August 30, 2012 N/A

5646 ImMODO California 2 LLC (Porterville 7) 1.5 CREST August 30, 2012 N/A

5647 SP Indigo Ranch B2, LLC 1.5 CREST October 5, 2012 N/A

5648 SP Indigo Ranch C2, LLC 1.5 CREST October 5, 2012 N/A

5656 SunE CREST 1, LLC 1.5 CREST October 5, 2012 N/A

5657 SunE CREST 2, LLC 1 CREST October 5, 2012 N/A

5658 SunE CREST 3, LLC 1 CREST October 5, 2012 N/A

5663 Ecos Energy, San Jacinto Solar 1.5 CREST November 20,

2012 N/A

5664 Ecos Energy, Lake Perris Solar 1.5 CREST November 20,

2012 N/A

5665 ImMODO California 2, LLC (Porterville 4) 1.5 CREST November 20,

2012 N/A

5666 ImMODO California 2 LLC (Porterville 3) 1.5 CREST November 20,

2012 N/A

5667 ImMODO California 2 LLC (Hanford 1) 1.5 CREST November 20,

2012 N/A

5668 ImMODO California 2 LLC (Hanford 2) 1.5 CREST November 20,

2012 N/A

62

5669 Coronus Joshua Tree East 1, LLC 1.5 CREST December 7, 2012 N/A





5675 DHS Solar 1, LLC (DHS Solar1) 1 CREST December 7, 2012 N/A

5676 DHS Solar 1,LLC (DHS Solar2) 1.5 CREST December 7, 2012 N/A

5680 Jimmy Solar LLC 1.5 CREST December 7, 2012 N/A

5684 Coronus Apple Valley East 1, LLC 1.5 CREST December 7, 2012 N/A

5685 Coronus Apple Valley East 2, LLC 1.5 CREST December 7, 2012 N/A

5692 Mitchell Solar, LLC 1.5 CREST December 7, 2012 N/A

5693 Rudy Solar, LLC 1.5 CREST December 7, 2012 N/A

5694 Madelyn Solar, LLC 1.5 CREST December 7, 2012 N/A

6361 Alta Wind XIII, LLC 100-180 ERR March 30, 2012 Resolution E-4564 approved February 28, 2013

5470 Victor Mesa Linda A, LLC 2 RAM February 14, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5477 Expressway Solar A, LLC 2 RAM February 14, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5478 Expressway Solar B, LLC 2 RAM February 14, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5566 Placer Solar, LLC 20 RAM February 14, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5567 Joshua Tree Solar Farm, LLC 20 RAM February 14, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5568 SEPV 8 12 RAM February 13, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5569 SEPV 9 9 RAM February 13, 2012 Advice Letter 2712-E was approved by the CPUC on April 30, 2012.

5621 LRE Agincourt, LLC 10 RAM October 17, 2012

Advice Letter 2785-E/E-A approved by the CPUC by Disposition Letter on November 14, 2012 (effective October 31, 2012).

5622 LRE Marathon LLC 20 RAM August 29, 2012


5626 FRV Orion Solar II LP 8 RAM August 29, 2012 Advice Letter 2785-E/E-A approved by the CPUC by Disposition Letter on November

63

14, 2012 (effective October 31, 2012).

5627 SunE Twisselman Solar LP 20 RAM August 29, 2012


5628 FRV Vega Solar LP 20 RAM August 29, 2012


5630 RE Adams East LLC 19 RAM August 29, 2012


8009 SDG&E (Sale #2) 103 SALES March 20, 2012 Resolution E-4515 approved July 12, 2012

8010 Energy America 40 SALES November 20, 2012

Resolution E-4572 approved February 28, 2013

5623 Smart Energy Capital (Riverside Knox A) 1 SPVP September 27,

2012 Terminated prior to submittal to CPUC

5624 Smart Energy Capital (Riverside Knox C) 1.5 SPVP September 27,

2012 Terminated prior to submittal to CPUC

5649 SunEdison Utility Solutions LLC (Corona) 1 SPVP September 28,

2012

Advice Letter 2802-E was approved by the CPUC on February 15, 2013

5650 SunEdison Utility Solutions, LLC (Hesperia) 1.5 SPVP September 28,

2012


5651 California PV Energy, LLC 1.2 SPVP September 28, 2012

Terminated prior to submittal to CPUC

5652 California PV Energy, LLC 1.3 SPVP September 28, 2012


5653 California PV Energy, LLC 2 SPVP September 28, 2012


a) San Diego Gas & Electric Company Sales Transaction (RAP ID 8009) 1

2

3

4

5

6

7

8

9

64

1

2

b) Energy America Sales Transaction (RAP ID 8010) 3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

2. Contract Amendment Administration 19

After execution, RPS contract terms and conditions may be changed by amendment. SCE 20

entered into 40 RPS contract amendments during the Record Period, shown below 21

65

Table X-16 RPS Contract Amendments49

January 1, 2012 Through December 31, 2012 RAP ID Project Description (and Amendment Number) Date Executed

3108 ORNI 18, LLC January 17, 2012

4210 Calleguas MWD - Conejos Letter Agreement to clarify SCE's telemetry requirements (a) October 2, 2012

5210 Solar Partners XVI, LLC June 29, 2012

5210 Solar Partners XVI, LLC September 24, 2012

5211 Solar Partners XVII, LLC June 29, 2012

5211 Solar Partners XVII, LLC November 19, 2012

5212 Solar Partners XVIII, LLC June 29, 2012

5212 Solar Partners XVIII, LLC September 24, 2012

5213 Solar Partners XIX, LLC June 29, 2012

5213 Solar Partners XIX, LLC September 24, 2012

5214 Solar Partners XX, LLC June 29, 2012

5214 Solar Partners XX, LLC November 19, 2012

5214 Solar Partners XX, LLC December 24, 2012

5240 RE Rio Grande, LLC September 28, 2012

5247 RE Rosamond Two, LLC September 28, 2012

5249 RE Victor Phelan Solar One, LLC September 28, 2012

5252 TA High Desert August 2, 2012

5283 Corcoran West, LLC March 30, 2012

49 Unless otherwise noted, amendments were made to power purchase agreements, also called renewable power purchase

and sale agreements, or RPS contracts.

66

5284 Silver State Solar Power South, LLC November 5, 2012

5351 Cascade Solar, LLC (SunEdison) March 26, 2012

5412 Solar Star California XIX, LLC (AVSP 1) December 27, 2012

5413 Solar Star California XX, LLC (AVSP 2) December 27, 2012

5463 Central Antelope Dry Ranch C, LLC July 3, 2012

5468 North Lancaster Ranch, LLC July 3, 2012

5469 Sierra Solar Greenworks, LLC July 3, 2012

5476 American Solar Greenworks July 3, 2012

5488 Garnet Solar Power Generation Station 1, LLC October 4, 2012

5493 RE Columbia 3, LLC September 28, 2012

5517 L-8 Solar Project, LLC Letter Agreement to clarify SCE's telemetry requirements (a) March 12, 2012

5518 Heliocentric, LLC Letter Agreement to clarify SCE's telemetry requirements (a) March 12, 2012

5626 FRV Orion Solar II, L.P. August 29, 2012

6313 Alta Windpower Development, LLC February 17, 2012

6314 Alta Wind II, LLC January 19, 2012

67

6319 Alta Wind VI , LLC March 13, 2012

6323 Alta Wind X, LLC February 17, 2012

6324 Alta Wind XI, LLC February 17, 2012

6330 North Hurlburt Wind, LLC January 12, 2012

6330 North Hurlburt Wind, LLC February 2, 2012

6331 South Hurlburt Wind, LLC January 12, 2012

Note (a): See Section 9(c) of this Chapter X for further details. 1

a) Solar Partners XX (RAP ID 5214) 2

CPUC Resolution E-4522, issued on October 29, 2012, approved SCE’s contracts with Solar 3

Partners XVII (Rio Mesa 2), and Solar Partners XX (Sonoran West). 4

On December 24, 2012, SCE and Solar Partners XX, LLC entered into an amendment 5

6

7

8

9

10

b) Recurrent (RAP IDs 5240, 5247, 5249, 5252, and 5493) 11

In 2012, SCE executed amendments to five PPAs with subsidiaries of Recurrent Energy (RE or 12

Recurrent). The amended PPAs, originating from SCE’s 2009 and 2010 RSC program, are: RE Rio 13

Grande (RAP ID 5240, 5 MW); RE Rosamond Two (RAP ID 5247, 20 MW); RE Victor Phelan (RAP 14

ID 5249, 20 MW); TA High Desert (RAP ID 5252, 20 MW); and RE Columbia 3 (RAP ID 5293, 10 15

MW).16

68

1

2

3

4

5

6

7

8

9

10

11

Table X-17

69

c) SPS Corcoran West, LLC (RAP ID 5283) 1

SPS Corcoran West (Corcoran) is a 19.75 MW solar PV ground mount project located in Kings 2

County, CA. The PPA was executed on February 10, 2011.3

4

The PPA, as 5

amended, was then approved by CPUC Resolution E-4509 on June 21, 2012. 6

d) Silver State Solar Power South, LLC (RAP ID 5284) 7

Silver State Solar Power South (Silver State) is a 250 MW solar PV ground mount project 8

located in Clark County, Nevada. The PPA was executed on February 7, 2011. 9

10

11

12

13

14

15

16

17

e) Cascade Solar (RAP ID 5351) 18

Cascade Solar is a 10 MW solar photovoltaic project executed as part of SCE’s 2010 SPVP 19

solicitation. 20

21

22

23

24

25

26

27

70

1

2

3

4

5

6

7

8

f) Solar Star CA (RAP IDs 5412 and 5413) 9

The Solar Star California XIX and Solar Star California XX projects, also known as Antelope 10

Valley Solar Project 1 (AVSP I) and Antelope Valley Solar Project 2 (AVSP 2), respectively, are owned 11

by the same parent company under separate PPAs with SCE for a total of 601 MW. 12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

71

g) Garnet Solar Power Generation (RAP ID 5488) 1

The PPA executed by SCE and Garnet Solar Power Generation Station 1, LLC (Garnet) provided 2

that Garnet would sell RPS-eligible energy to SCE from a 4.78 MW concentrated photovoltaic (CPV) 3

generating facility. 4

5

6

7

8

9

10

11

12

13

h) Alta Wind VI, LLC (RAP ID 6319) 14

15

16

17

18

19

20

21

22

23

50

72

3. Contract Assignment Administration 1

RPS contracts may only be assigned with the written consent of the counterparty, which may not 2

be unreasonably withheld. There are many reasons why RPS contract counterparties seek to assign their 3

contracts. For example, the counterparty might want to sell or transfer the project to a new entity, assign 4

the contract to a lender as security for a loan, or change control of the project.51 Table X-18 lists the 26 5

contract assignments to which SCE consented during the Record Period. 6

51 SCE provides the assignment documents in its reply to the Master Data Request.

73

Table X-18 RPS Contract Assignments


RAP ID

Project Type of Assignment Consent Signed

5249 RE Victor Phelan Solar One, LLC December 7, 2012

5252 TA - High Desert, LLC January 27, 2012

5252 TA - High Desert, LLC August 2, 2012 5396 SEPV 1 July 11, 2012 5397 SEPV 2 July 11, 2012 5408 Solar Power, Inc. February 29, 2012 5411 Solar Power, Inc. March 29, 2012 5412 Solar Star California XIX, LLC December 27, 2012 5413 Solar Star California XX, LLC December 27, 2012

5447 Lancaster Dry Farm Ranch B December 24, 2012

5448 Lancaster WAD B December 24, 2012

5459 Victor Dry Farm Ranch A December 24, 2012

5460 Victor Dry Farm Ranch B December 24, 2012

5462 Central Antelope Dry Ranch December 24, 2012

5470 Victor Mesa Linda A December 24, 2012

5477 Expressway Solar A December 24, 2012

5478 Expressway Solar B December 24, 2012

5488 Garnet Solar Power Generation Station 1, LLC October 4, 2012

5517 L-8 Solar Project, LLC June 20, 2012 5518 Heliocentric, LLC May 21, 2012 5567 Joshua Tree Solar Farm November 19, 2012 5568 SEPV 8 May 15, 2012 5569 SEPV 9 May 15, 2012

5622 LRE Marathon, LLC November 26, 2012 6319 Mustang Hills, LLC September 14, 2012

6333 AES - Mountain View Power Partners, LLC June 20, 2012

74

4. Energy Delivery Performance Administration 1

Some of SCE’s RPS contracts include provisions that require the sellers to meet certain energy 2

delivery obligations. During the negotiations of the RPS contracts, SCE and the seller set expected 3

annual net energy production targets for the specific projects. These annual production targets function 4

as the bases for the determination of whether, in a given term year, the projects meet their energy 5

delivery obligations. The energy delivery obligation calculation may be performed on either an annual 6

or multi-year basis depending on contract terms. Regardless of timing of the calculation, the result is 7

either a comparison of the actual annual deliveries or the average annual delivery over multiple years to 8

determine if the energy delivery obligation has been met. 9

SCE examines the production of each project and determines if the project has met the applicable 10

energy delivery requirement. Depending on the contract, the seller may request credit for lost 11

production if the loss is attributed to Lost Output as defined in the PPA. If a project does not meet its 12

energy delivery requirements after supplementing their production kWh with confirmed Lost Output, the 13

project may be subject to liquidated damages known as an Energy Replacement Damage Amount. 14

During the Record Period, calculations regarding annual production were performed on nine 15

contracts. Seven contracts were found to have either met or exceeded their annual net energy production 16

target. Two contracts did not meet their required target. These two failures are further described below. 17

a) Ventura Regional Sanitation District (RAP ID 1221) 18

19

20

21

b) ORNI 18 (North Brawley) (RAP ID 3108) 22

23

24

75

1

2

3

5. Uncontrollable Force Administration 4

SCE’s RPS contracts include provisions that may excuse an RPS project from performing certain 5

contractual obligations to the extent the project can demonstrate that the occurrence of an uncontrollable 6

force, or a circumstance beyond its reasonable control as defined in the applicable agreements 7

(otherwise known as a force majeure), prevented the project from performing such obligations. 8

Whenever an RPS contract holder claims that an uncontrollable force caused it to fail to meet its 9

contractual obligations, SCE undertakes the following activities: 10

� Determines whether the claim was submitted within the contractually-required period, 11

which is typically two weeks. 12

� Requires that the counterparty submit sufficient evidence to substantiate the claim that an 13

uncontrollable force event occurred. This may include meteorological or weather reports 14

to support a claim of weather damage, construction and equipment specifications, 15

manufacturer maintenance manuals and bulletins, the project’s operations and 16

maintenance/repair logs, copies of insurance claims, damage assessments, failure reports, 17

and other relevant materials. 18

� Evaluates whether the suspension of performance was of no greater scope and of no 19

longer duration than was required by the uncontrollable force, and that the RPS contract 20

holder used its best efforts to remedy its inability to perform. 21

52 In accordance with the provisions in the PPA, if in any Term Year Seller fails to meet Seller's Annual Energy Delivery

Obligation, then Seller shall be subject to an Energy Replacement Damage Amount penalty. In the calculation, this amount is a function of the average of the Market Price for all Settlement Intervals in the Term Year in $ / kWh, minus the PPA Energy Price in $ / kWh. For ORNI, this difference is negative (i.e., the PPA Energy Price is higher than the average Market Price). However, for the Record Period, if the result of the calculation is zero or less, Seller is not obligated to pay an Energy Replacement Damage Amount.

76

If SCE grants the claim, and if the contract does not provide otherwise, the RPS contract 1

counterparty will receive lost output credit (kWh) for the period of the event up to 365 days, despite a 2

failure to deliver power to SCE. Lost output credit is applied to the annual production amounts found in 3

the contract to offset any replacement energy damages to compensate SCE customers for 4

nonperformance of the contract. Table X-19 shows the status of the three uncontrollable force claims 5

tendered to SCE or pending during the Record Period: 6

Table X-19 RPS Uncontrollable Force Claims Tendered and/or Pending


6. Dispute Resolution and Litigation 7

Details on selected RPS Project dispute resolutions and litigation activities during the Record 8

Period are provided below. 9

a) Bonneville Power Administration 10

11

12

13

14

15

16

17

18

RAP ID


5240 RE Rio Grande, LLC

Claim submitted on Dec 7, 2011, stating interconnection would take longer than Seller hoped.

SCE denied Claim on Jan 10, 2012; Seller withdrew claim on Dec 19, 2012

5247 RE Rosamond Two, LLC

Claim submitted on Dec 7, 2011, stating interconnection would take longer than Seller hoped.

SCE denied Claim on Jan 10, 2012; Seller withdrew Claim on Dec 19, 2012

5397 SEPV 2 Claim submitted on August 7, 2012 due to damage caused by lightning strike.

SCE accepted Seller’s Claim; project resumed normal operation on September 25, 2012

77

b) Western Water and Power Production, Limited (RAP ID 1223) 1

2

3

4

5

6

7

8

9

10

c) California Solar 10 (RAP ID 5231) 11

California (“CA”) Solar 10 is a 484 MW solar thermal parabolic trough project in Blythe, CA. 12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

78

1

2

3

d) LightSource Renewables (RAP IDs 5237, 5238, and 5239) 4

As part of the 2009 RSC Program, on December 29, 2009, SCE executed three PPAs with 5

LightSource Renewables (LSR): LSR Kramer South, North Edwards Solar, and Boron Solar. 6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

e) Sustainable Energy Capital Partners (RAP ID 5253) 25

26

27

79

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

f) Silverado (RAP IDs 5463, 5468, 5469, and 5476) 16

Central Antelope Dry Ranch B, LLC (RAP ID 5463), North Lancaster Ranch, LLC (RAP ID 17

5468), Sierra Solar Greenworks, LLC (RAP ID 5469), and American Solar Greenworks, LLC (RAP ID 18

5476)( together, the Silverado PPAs) are four projects originally signed as part of SCE’s 2010 RSC 19

solicitation.20

21

22

23

24

25

26

27

80

1

2

3

4

5

6

7

g) Clear Peak Energy, Inc. (RAP ID 5491) 8

On November 15, 2010, SCE and Clear Peak Energy, Inc. (Clear Peak) executed a Renewable 9

Power Purchase and Sale Agreement (the PPA) in connection with SCE’s 2010 RSC RFO for an 8.5 10

MW solar photovoltaic facility. The PPA was approved by the CPUC on December 15, 2011 via 11

Resolution E-4445. 12

13

14

15

16

17

18

19

20

21

22

23

h) Alta Curtailments (RAP IDs 6314 - 6319 and 6321) 24

25

26

27

81

1

2

3

4

5

6

7

8

9

10

11

12

i) Sand Canyon (RAP ID 6341) 13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

82

1

2

7. Contract Termination 3

Table X-20shows the 50 RPS contracts that terminated during the Record Period. 4

Table X-20 RPS Contract Terminations


Project Contract Capacity MW

Contract Type

Termination Date

1209 Imperial Valley Resource Recovery LLC 16.4 ERR December 4, 20121

1219 FlexEnergy, LLC / Flex-Bernardino 2 RSC5 April 4, 20122

1220 FlexEnergy, LLC / Flex-Kern 5 RSC5 April 4, 20122

5210 Solar Partners XVI, LLC 200 ERR November 5, 20123

5211 Solar Partners XVII, LLC 200 ERR December 24, 20121

5212 Solar Partners XVIII, LLC 200 ERR December 4, 20123

5213 Solar Partners XIX, LLC 200 ERR December 4, 20123

5231 CA Solar 10, LLC 484 ERR March 29, 20123

5351 Cascade Solar LLC 10 SPVP April 15, 20124

5356 Photon Solar LLC 1.038 SPVP May 7, 20123












5389 SunEdison Utility Solutions, LLC (GE Real Estate) 1 SPVP January 15, 20124

5390 SunEdison Utility Solutions, LLC (Master Development - Corona) 1 SPVP May 6, 20124

5392 Tioga Solar XIX, LLC 0.658 SPVP March 1, 20123

5393 Greenpower Williams, LLC 1.134 SPVP May 7, 20123


83


5409 Advanced Solar Integration Technologies, LLC 0.956 SPVP May 7, 20123

5486 Blythe Solar Power Generation Station 1, LLC 4.7 RSC5 June 7, 20122

5487 Littlerock Solar Power Generation Station 1, LLC 5 RSC5 December 18, 20122

5489 Lucerne Solar Power Generation Station 1, LLC 14 RSC20 June 7, 20122

5491 Clear Peak Energy, Inc. 8.5 RSC20 March 7, 20123

5586 Victor Mesa Linda B2 1.5 CREST August 21, 20124

5593 ImMODO California 2, LLC (Seville 1) 1.5 CREST August 24, 20123




5608 Gaskell Suntower, LLC 105 ERR April 30, 20123

5611 Victor Mesa Linda D2 1.5 CREST August 21, 20124

5612 Victor Mesa Linda E2 1.5 CREST August 21, 20124

5616 Victor Mesa Linda C2 1.5 CREST August 21, 20124

5623 Smart Energy Capital (Riverside Knox A) 1 SPVP November 30, 20123

5624 Smart Energy Capital (Riverside Knox C) 1.5 SPVP November 30, 20123

5651 California PV Energy, LLC 1.2 SPVP December 7, 20123

6336 Echanis, LLC 40 ERR December 6, 20122

6338 PacifiCorp 50 ERR December 31, 20125

6340 Puget Sound Energy Inc. III 50 ERR March 31, 20125

8006 CE2 Environmental Opportunities I, LP N/A REC Only March 30, 20125

8007 CE2 Carbon Capital, LLC N/A REC Only March 30, 20125

8009 SDG&E (Sale #2) 103 SALES December 31, 20125

Notes:

(1) Mutual Termination between the parties

(2) Seller terminated PPA

(3) SCE exercised applicable PPA termination right provisions

(4) SCE terminated PPA pursuant to Seller’s request for termination

(5) PPA expired.

Details on selected RPS Project terminations during the Record Period are provided below. 1

a) Imperial Valley Resource Recovery (RAP ID 1209) 2

3

4

5

6

84

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

b) Solar Partners XVII (RAP ID 5211) 18

CPUC Resolution E-4522 issued on October 29, 2012 approved Solar Partners XVII (Rio Mesa 19

2), and Solar Partners XX (Sonoran West) PPAs. 20

21

22

23

24

25

26

85

1

2

c) ImMODO California (RAP IDs 5593, 5594, 5595, and 5596) 3

4

5

6

7

8

9

8. RPS Projects That Achieved Commercial Operation 10

Table X-21 shows the 22 RPS projects that came on-line during the Record Period. 11

Table X-21 RPS Contracts that Achieved Commercial Operation


Project Commercial On-line Date (a)

Capacity (MW)

Estimated Firm Operation Date (b)

4208 Lower Tule River Irrigation District August 1, 2012 0.956 August 1, 2012 (c)

4209 White Mountain Ranch August 1, 2012 0.29 August 1, 2012 (c)

4210 Calleguas MWD – Conejos October 1, 2012 0.55 October 1, 2012 (c)

5369 Golden Springs Develop Co., LLC (Bldg. C) February 10, 2012 1.2 February 10, 2012 (c)

5370 Golden Springs Develop. Co, LLC (Bldg. D) April 2, 2012 1.3 April 2, 2012 (c)

5371 Industry Metrolink PV 1, LLC April 3, 2012 1.5 April 3, 2012 (c)

5394 SS San Antonio West LLC July 20, 2012 1.50 December 13, 2012 (c)

5396 SEPV1, LLC May 4, 2012 2 January 11, 2013 (c)

5397 SEPV2, LLC June 5, 2012 2 January 10, 2013 (c)

5408 North Palm Springs Investments, LLC April 2, 2012 2.5 April 2, 2012 (c)

5411 North Palm Springs Investments, LLC November 2, 2012 4 November 2, 2012 (c)

5510 USFS San Dimas Technology and Development Center July 23, 2012 0.25 July 23, 2012 (c)

5517 L-8 Solar Project, LLC June 1, 2012 1.5 June 1, 2012 (c)

5518 Heliocentric, LLC March 28, 2012 1.5 March 28, 2012 (c)

6304 Mountain View Power Partners, IV February 23, 2012 49 August 23, 2012

6307 Windstar Energy, LLC January 27, 2012 120 July 27, 2012

6319 Mustang Hills, LLC March 17, 2012 150 September 17, 2012

86

6321 Alta Wind VIII, LLC January 31, 2012 150 July 31, 2012

6331 South Hurlburt Wind, LLC February 14, 2012 290 February 14, 2013

6332 Horseshoe Bend Wind, LLC March 28, 2012 290 March 28, 2013

Total MW 1,070.046

Notes:

a) Commercial On-line Date is referred to as Initial Operation Date in many RAP contracts. b) Firm Operation Date determines final project contract capacity. c) As SPVP and CREST PPAs do not include provisions for a Firm Operation date, the date listed here is that of the project’s Capacity Verification.

9. Collateral 1

There are two types of Collateral that are posted: Development Security and Performance 2

Assurance. Each type is discussed in detail below. 3

a) Development Security 4

SCE contract managers work closely with RPS project developers to assist them in meeting 5

project milestones so they can begin operation and contribute to the State’s renewable goals. As SCE 6

has reported in other contexts, these projects can face a number of challenges, including transmission or 7

permitting delays and difficulty securing financing. As part of its contract administration activities, SCE 8

diligently monitors the progress of RPS projects and provides on-going support to move these projects 9

forward for the benefit of its customers. However, in order to mitigate the risk of a project’s failure to 10

reach full development, SCE requires counterparties to post development security to defray some of the 11

costs of replacing the failed development. 12

The administration and tracking of this collateral has been assigned to SCE’s Corporate Finance 13

and Risk Control Groups. However, the contract managers within SCE’s RAP Group still serve as the 14

primary contact for collateral issues. SCE’s Risk Control Group directly handles the routine collateral 15

posting transactions with the counterparty and contract managers entering key security data into WES53 16

so the basic data is readily available. 17

One significant milestone to be met by RPS projects is the posting of a required development 18

security to ensure that the promised project will be developed. Development securities are typically 19

53 As described in Chapter IX, SCE uses a wholesale energy system (WES), a computer-based comprehensive contract

management/administration system, to track contract data.

87

posted in the form of cash or letter of credit. At the end of the Record Period, the value of all RPS 1

contract development security held by SCE was Listed below are the significant 2

activities that took place during the Record Period related to RPS project development security. 3

Table X-22 RPS Contract Development Security


Project Development Security

4202 Bishop Tungsten Development, LLC

4206 Isabella Fish Flow Hydroelectric Project LLC

4207 Monte Vista Water District

4210 Calleguas MWD – Conejos

5210 Solar Partners XVI, LLC

5212 Solar Partners XVIII, LLC

5213 Solar Partners XIX, LLC

5283 Corcoran West, LLC

5284 Silver State Solar Power South LLC

5297 FRV Regulus Solar, LP

5298 FRV Adobe Solar, LP

5300 FRV Mojave Solar 4, LP

5356 Photon Solar LLC












5394 SS San Antonio West LLC



5412 Solar Star XIX

88

5413 Solar Star XX

5415 Solar Star XIII

5439 Powhatan Solar Power Generation Station 1, LLC

5440 Otoe Solar Power Generation Station 1, LLC

5442 Navajo Solar Power Generation Station 1, LLC

5463 Central Antelope Dry Ranch C

5468 North Lancaster Ranch, LLC

5469 Sierra Solar Greenworks, LLC

5470 Victor Mesa Linda A

5476 American Solar Greenworks, LLC

5477 Expressway Solar A

5478 Expressway Solar B

5485 Nicolis, LLC

5486 Blythe Solar Power Generation Station 1, LLC

5487 Littlerock Solar Power Generation Station 1, LLC

5488 Garnet Solar Power Generation Station 1, LLC

5489 Lucerne Solar Power Generation Station 1, LLC

5490 Tropico, LLC

5494 McCoy Solar, LLC

5496 Industry Solar Power Generation Station 1, LLC

5508 Adelanto 10, LLC

5509 Newberry Solar 1, LLC

5520 Treen Solar 1, LLC

5521 Treen Solar 2, LLC

5522 Annie Power, LLC

5523 JRam Solar 1, LLC



5526 Ayden Power, LLC

5527 CSC Solar, LLC

5528 CSC Solar I, LLC

5529 CSC Solar II, LLC

5530 Erika Solar, LLC

89

5531 Carly Solar, LLC

5532 Goodbar Solar 1, LLC

5533 DT Solar 1, LLC



5536 Sandra Energy, LLC

5537 Abby Power, LLC

5538 Cami Solar, LLC

5539 Dreamer Solar, LLC

5540 Josh Energy, LLC

5541 Drew Energy, LLC

5542 Amy Solar, LLC

5543 Rachel Energy, LLC

5544 MJ Power, LLC

5545 Kell Solar 1, LLC

5546 Kell Solar 2, LLC

5547 Leolani Solar 1, LLC

5548 Leolani Solar 2, LLC

5549 Voyager Solar 1, LLC



5552 Niner Energy 1, LLC



5555 Lola Energy 1, LLC

5556 Lola Energy 2, LLC

5557 D2 Solar 1, LLC

5558 D2 Solar 2, LLC

5559 Becca Solar, LLC

5560 Toro Power 1, LLC

5561 Toro Power 2, LLC

5562 Lancaster Solar 5 LLC

5563 Lancaster Solar 4 LLC

5564 Coronus Hesperia West 1

5566 Placer Solar

5567 Joshua Tree

5568 SEPV 8

90

5569 SEPV 9

5587 ImMODO California 2, LLC (Exeter 1)



5590 ImMODO California 2, LLC (Lindsay 1)



5597 ImMODO California 2, LLC (Ivanhoe 1)



5600 ImMODO California 2, LLC (Porterville 1)



5603 ImMODO California 2, LLC (Tulare 1)

5604 ImMODO California 2, LLC (Tulare 2)

5605 Ever CT Solar Farm, Site 1A

5606 Ever CT Solar Farm, Site 1B

5607 Ever CT Solar Farm, Site 2A

5609 Ever CT Solar Farm, Site 2B

5610 Ever CT Solar Farm, Site 2C

5613 East Valley Greenworks C

5614 East Valley Greenworks D

5615 East Valley Greenworks E

5618 Marinos Ventures LLC

5619 ImMODO California 2 LLC (Farmersville 1)


5621 LRE Agincourt, LLC

5622 LRE Marathon LLC

5626 FRV Orion Solar II LP

5627 SunE Twisselman Solar LP

5628 FRV Vega Solar LP

91

5630 RE Adams East LLC


5632 SP Indigo Ranch A2

5633 Coronus 29-Palms North 1 LLC


5635 Coronus Hesperia West 2 LLC

5636 Coronus Yucca Valley East 1 LLC

5637 Coronus Yucca Valley East 2 LLC


5645 ImMODO California 2 LLC (Porterville 6)

5646 ImMODO California 2 LLC (Porterville 7)

5647 SP Indigo Ranch B2

5648 SP Indigo Ranch C2

5649 SunEdison Utility Solutions LLC (Corona)

5650 SunEdison Utility Solutions, LLC (Hesperia)

5652 California PV Energy, LLC

5653 California PV Energy, LLC

5656 SunE CREST 1, LLC



5667 ImMODO California 2 LLC (Hanford 1)

5668 ImMODO California 2 LLC (Hanford 2)

5669 Coronus Joshua Tree East 1, LLC





5684 Coronus Apple Valley East 1, LLC

5685 Coronus Apple Valley East 2, LLC

6361 Alta XIII

b) Performance Assurance 1

On or before a project’s Commercial Operation Date (COD), RPS contracts require posting of 2

“performance assurance,” which is collateral for performance during the term of the PPA. This is 3

92

distinct from “development security” described in the previous section, which provides collateral for 1

development of the project prior to commercial operation. The collateral amount may be posted in the 2

form of cash, letter(s) of credit, or a guaranty from a creditworthy entity acceptable to SCE. As of the 3

end of the Record Period, the total amount of RPS project performance assurance-related collateral held 4

by SCE was . Listed below are the significant activities that took place during the 5

Record Period related to RPS project performance assurance. Some counterparties provide performance 6

assurance in multiple letters of credit. 7

Table X-23 RPS Contract Performance Assurance


10. Other Contract Administration Activity 8

a) Temescal Canyon RV, LLC (RAP ID 5277) 9

On July 29, 2011, SCE and Temescal Canyon RV, LLC (Temescal) executed a CREST PPA for 10

a 1.5 MW solar photovoltaic project located in Corona, CA. On the same day, SCE and Temescal 11

Canyon RV, LLC also executed a Letter Agreement clarifying CAISO obligations and related telemetry 12

requirements contained within Appendix E in the CREST PPA (Letter Agreement). 13

Pursuant to the CREST PPA, Temescal is required to enter into several agreements with the 14

CAISO, including, among others, a Participating Generator Agreement (PGA) and Meter Service 15

Agreement (MSA). Participating Generators, as defined in the CAISO tariff, are required to install and 16

maintain a telemetering system capable of transmitting data from a CAISO-approved meter and the 17

Generating Facility’s control system to the CAISO’s energy communication network. Therefore, in 18

RAP ID

Project Performance Assurance

1209 Imperial Valley Resource Recovery LLC

6304 Mountain View Power Partners, IV

6319 Mustang Hills, LLC

6320 Pinyon Pines Wind I, LLC

6321 Alta Wind VIII, LLC

6322 Pinyon Pines Wind II, LLC

93

order to comply with the CREST PPA and the CAISO tariff’s telemetry requirements, the Participating 1

Generator is required to procure and install, at its own cost, a Remote Intelligent Gateway, commonly 2

referred to as a data processing gateway (DPG). 3

Depending on the project location, DPG systems generally cost between $80,000 and $120,000. 4

However, to assist small generators in lowering the cost of meeting this requirement, the Letter 5

Agreement grants an option to meet the telemetry requirements of the CAISO tariff by connecting to an 6

aggregated DPG (ADPG), to be made available by SCE, in lieu of procuring and installing its own DPG. 7

If a Participating Generator elects to satisfy the CAISO requirements via the ADPG, SCE would waive 8

the Participating Generator requirement under the CREST PPA to procure and install a DPG on the 9

conditions that Producer will, within 270 days of receipt of notice from SCE, procure and install all 10

equipment and systems necessary to connect to the ADPG via a dedicated T1 line or other method 11

acceptable to SCE. Furthermore, if a Participating Generator elects to connect to an ADPG, SCE would 12

cap the cost of installing hardware to connect to the ADPG at ten thousand dollars ($10,000). To elect 13

to meet the telemetry requirements of the CAISO tariff, both Participating Generator and SCE would 14

sign the Letter Agreement. 15

While producers are not obligated to accept SCE’s Letter Agreement, SCE offers the Letter 16

Agreement to every Participating Generator who has an executed CREST Agreement with SCE. 17

Temescal Canyon, RV LLC was the first Participating Generator to execute the Letter Agreement. To 18

accommodate small generators in SCE’s other procurement programs, SCE is expanding the use of the 19

Letter Agreement and ADPG solution to Participating Generators with executed Solar PV Program 20

power purchase agreements with SCE. Below is a list of CREST Producers in addition to Temescal that 21

have elected to take advantage of the ADPG solution. 22

94

Table X-24

b) Windstar Energy, LLC (RAP ID 6307) 1

Windstar Energy LLC (Windstar) is a 120 MW wind project located in Tehachapi, California. 2

The PPA was executed on March 8, 2005. 3

4

5

6

7

8

9

10

11

12

C. Contract Compliance 13

Compliance programs have been developed to ensure that RPS projects adhere to the terms of 14

their contracts, and to integrate these projects effectively to the electric system grid. This section will 15

discuss the following contract compliance programs: (1) renewable capacity verification; (2) measuring 16

energy deliveries; (3) active monitoring, (4) WREGIS fees, and (5) RPS project insurance verification. 17

1. Renewable Capacity Verification 18

SCE’s capacity verification activities for renewable projects are designed to ensure that SCE’s 19

customers receive the energy for which SCE has contracted. As new renewable contracts do not contain 20

firm capacity provisions, the verification serves a different purpose than those in firm PURPA contracts 21

RAP ID Project Name Technology Contract Capacity (kW)

4210 Calleguas MWD - Conejos PV Ground 550 5517 L-8 Solar Project, LLC PV Ground 1,500 5518 HelioCentric, LLC PV Ground 1,500

95

called CapDemo and CapPerformance. Renewable capacity verifications are generally a one-time event 1

performed either prior to the contract becoming commercial or around the contractual Firm Operation 2

Date.54 This activity generally consists of a site visit to verify the equipment listed in the contract has 3

been installed and in some cases the collection of meter data for a chosen interval. The verification is 4

intended to determine the maximum capacity capability of the project. From that demonstrated capacity, 5

the energy delivery performance requirements for energy over a period specified in the contract is 6

derived. 7

During the Record Period there were 20 renewable projects that underwent capacity tests. 12 of 8

these projects passed the verification process with a site inspection for determination of the installed 9

equipment. Eight of these projects were from the SPVP-IPP program. SPVP-IPP uses the sum of the 10

direct current (DC) ratings of the solar photovoltaic modules as the capacity metric because the program 11

size is based upon the DC rating. Of these eight SPVP-IPP projects, four were verified to have 12

equipment and equipment ratings that met the contract requirements during the initial site visit. These 13

were contracts RAP ID 5369, 5370, 5408 and 5411. 14

However, four projects were found to have installed equipment whose ratings exceeded the 15

contract amounts. These were contracts RAP ID 5371, 5394, 5396 and 5397. Two of these projects 16

remedied the over-installation by isolating the extra equipment by removing the module lead wires 17

because physical removal of the modules would have impacted the structural integrity of the solar array. 18

This was verified with a return site visit to each project. The remaining two projects had committed to 19

remedy the situation as well. However, on multiple return site visits it was determined they had 20

physically removed modules, then restored the modules and attempted to isolate the modules by 21

removing the string fuses, and had restored disconnected strings to service and removed others from 22

service to cover for equipment failures, which SCE does not consider to be in compliance with the 23

54 See Table X-6, “RPS Contracts that Achieved Commercial Operation” above for a list of contracts that may have been

eligible for a verification test. Note that due to different testing schedules established in each PPA, not all contracts in this table were tested during the Record Period.

96

PPAs. The projects were instructed to physically remove the extra modules. This remedy for the over-1

installation had not been completed before the end of the Record Period, but in early 2013 both projects 2

removed the excess panels. The following table lists the units tested and the results as of the end of the 3

Record Period. 4

Table X-25 Renewable Capacity Verifications


RAP ID

Project Date of Capacity Test

Capacity (MW)

4202 Bishop Tungsten Development, LLC September 27, 2012

250

4208 Lower Tule River Irrigation District July 31, 2012

1,400 4209 White Mountain Ranch, LLC July 28, 2012 312 4210 Calleguas MWD - Conejos August 27, 2012 745

5369 Golden Spring Development Co., LLC (Bldg. C1) February 3, 2012

1,335.7401

5370 Golden Spring Development Co., LLC (Bldg. D) March 28, 2012

1,434.4401 5371 Industry Metrolink PV 1, LLC April 26, 2012 1,999.2001 5394 SS San Antonio West LLC August 23, 2012 1,861.1601 5396 SEPV1, LLC April 26, 2012 2,268.0002 5397 SEPV2, LLC May 24, 2012 2,321.3402 5408 North Palm Springs 1A March 30, 2012 2,833.6001 5411 North Palm Springs 4A May 4, 2012 4,958.8001

5510 USDA Forest Service San Dimas Technology Center August 6, 2012

250 5517 L-8 Solar Project, LLC May 23, 2012 1,500 5518 Heliocentric, LLC March 19, 2012 1,500

6319 Alta Wind VI, LLC (Mustang Hills) February 6, 2012

150,000

6321 Alta Wind VIII, LLC (Brookfield) February 6, 2012 150,000

6330 North Hurlburt Wind, LLC May 10, 2012 265,000 6331 South Hurlburt Wind, LLC August 15, 2012 290,000 6332 Horseshoe Bend Wind, LLC August 15, 2012 290,000

Notes:

1. The SPVP-IPP project capacity is reported in kW DC to the nearest watt.

2. Capacity oversized for the Record Period.

97

2. Measuring Energy Deliveries 1

SCE uses a combination of meter and schedule data to calculate payments for the 49 RPS 2

projects that delivered energy during the Record Period. The schedules are established daily between 3

the parties. CAISO meters are four-quadrant interval meters that measure forward and reverse watts and 4

VARs. The meters are capable of communicating with a remote system for data collection. The CAISO 5

reads these meters directly for settlements. SCE also reads these meters remotely, partly to check the 6

data and partly to use the data in other ways as provided in the contracts. Generally, RPS generators are 7

required to obtain CAISO-approved metering for their facilities. Projects previously using the 8

Metropolitan Water District or SCE back-up meters are now using CAISO meters. SCE maintains its 9

own meters at some of the RPS projects. These meters are used for verification, backup RPS reporting 10

purposes, and in some cases, monthly payments. 11

During the Record Period, energy received by SCE from 30 RPS projects was measured using 41 12

CAISO meters (some projects require multiple meters), one RPS project was measured using its intertie 13

schedule from the Imperial Irrigation District, and 10 CREST projects were measured using SCE real 14

time energy meters (RTEMs). 15

3. Active Monitoring 16

D.10-06-004 requires SCE to (a) devise a method to actively monitor each seller’s compliance 17

with Standard Term and Condition 655 (STC 6) and related contract terms, (b) administer that active 18

monitoring, and (c) make an affirmative showing in each ERRA proceeding of its method for active 19

monitoring and the results of that monitoring. This shall be part of SCE’s showing of reasonable 20

contract administration of all contract terms, inclusive of obligations both before and after the project’s 21

commercial operation date, as appropriate.56 22

55 STC 6 requires that the seller warrant throughout the term of the PPA that (i) the project qualifies and is certified as an

ERR and (ii) the output qualifies under requirements of the California RPS. The only exception is upon a change in law, wherein seller is contractually obligated to use commercially reasonable efforts to comply with the change in law (paraphrased for simplicity, for actual STC 6 verbiage see D.08-04-009, Appendix A, p. 6).

56 D.10-06-004, p. 21, OP No. 2.

98

SCE’s method to actively monitor each seller’s compliance with STC 6 consists of: (1) 1

requesting the seller to provide a copy of the project’s California Energy Commission (CEC) pre-2

certification within 365 days after the effective date of the contract and requiring the project to attain full 3

certification from the CEC shortly after the project begins commercial delivery; (2) monitoring changes 4

in law or regulations that may affect RPS eligibility; (3) monthly monitoring of the CEC website to 5

verify that facilities are RPS-certified via each facility’s unique RPS ID (cross-checked to the CEC 6

certification); and (4) verifying the RPS ID during routine WREGIS registration and maintenance. 7

Additionally, SCE performs site visits, capacity demonstrations, and capacity verifications during the 8

construction and commercial operation phases of the project to ensure that the project is in compliance 9

with the contract. 10

During the Record Period, SCE executed an additional 164 RPS contracts. Those projects are in 11

varying stages of delivering a copy of the individual project’s CEC pre-certification. 12

Currently, SCE’s entire portfolio of RPS-eligible contracts consists of proven applications of 13

landfill gas, biomass, digester gas, geothermal, small hydro, conduit hydro, solar thermal, solar PV, and 14

wind technologies as generating facilities. During the Record Period, SCE’s regulatory group routinely 15

monitored new legislation and regulations. No change in law or regulation affected the RPS eligibility 16

of any of these technologies. As a result, no requests were made to sellers to make commercially 17

reasonable efforts to comply with changes in law as provided in the contracts. 18

SCE’s contract compliance includes monthly monitoring of the CEC website to verify that 19

facilities are RPS-certified. This review is imbedded in the process for WREGIS registration and 20

maintenance. During the Record Period, no RPS ID inconsistencies were noted for RPS contracts when 21

validating or maintaining WREGIS data. 22

Capacity verifications are discussed in section C.1 of this chapter. In addition to the 20 capacity 23

verifications, site visits were conducted at four other operational projects. Also, visits were conducted at 24

project sites during various phases of those projects construction. See Table X-10 below. As a result of 25

those visits, no inquiries from observations at those sites were necessary, and all visits revealed that the 26

projects were complying with the contract terms including STC 6. 27

99

Below is a summary of SCE’s Active Monitoring activities during the Record Period. 1

Table X-26 RPS Active Monitoring


4. Western Renewable Energy Generation Information System (WREGIS) 2

Pursuant to Senate Bill 1078 and Public Utilities Code § 399.13, the CEC developed an 3

electronic accounting and tracking system to verify retail sellers’ compliance with the RPS. This 4

RAP ID Project Site Visit During Record Period

Capacity Verification (a)

4202 Bishop Tungsten Development, LLC X X

4208 Lower Tule River Irrigation District X X

4209 White Mountain Ranch, LLC X X

4210 Calleguas MWD – Conejos X X

5005 Sunray Energy X

5207 NRG Solar Blythe LLC X

5208 Solar Partners I, LLC X

5369 Golden Spring Development Co., LLC (Bldg. C1) X X

5370 Golden Spring Development Co., LLC (Bldg. D) X X

5371 Industry Metrolink PV 1, LLC X X

5394 SS San Antonio West LLC X X

5396 SEPV1, LLC X X

5397 SEPV2, LLC X X

5408 North Palm Springs 1A X X

5411 North Palm Springs 4A X X

5508 Adelanto 10 X

5510 USDA Forest Service San Dimas Technology Center X X

5517 L-8 Solar Project, LLC X X

5518 Heliocentric, LLC X X

6319 Alta Wind VI, LLC (Mustang Hills) X X

6321 Alta Wind VIII, LLC (Brookfield) X X

6330 North Hurlburt Wind, LLC X X

6331 South Hurlburt Wind, LLC X X

6332 Horseshoe Bend Wind, LLC X X

Notes:

Not all projects require capacity verifications because they are either not yet constructed or operating, or they have already been

verified in a prior Record Period.

100

system, WREGIS, became operational in June 2007. SCE participates in WREGIS pursuant to Public 1

Utilities Code § 399.13 and is subject to the compliance requirements of the CEC and the Commission. 2

During the Record Period, SCE had 185 facilities registered in the WREGIS system. Those 3

facilities were comprised of a total of 208 individually-registered generating units representing all 4

eligible renewable PURPA and utility-owned projects, and most RPS contracts. All other RPS projects 5

register their facilities separately and then transfer their RPS credits to SCE for compliance purposes. 6

However, there was a discrepancy with the 2007 generation from the two Ormesa Geothermal PURPA 7

projects where the operator had been introducing energy from a previously terminated project (Geo East 8

Mesa 3 or GEM). This was resolved by consolidating the three Qualifying Facility PURPA projects into 9

one PPA with negotiated terms. Details of this transaction were included in SCE’s 2007 ERRA filing. 10

In its 2012 ERRA filing, SCE pointed out that the CEC had certified GEM as RPS-eligible as of April of 11

2011 and that SCE was appealing this determination with the CEC and requesting that the GEM unit 12

certification be retroactive to 2007. The CEC ultimately denied SCE’s request and ruled consistent with 13

its 2007 RPS Procurement Verification Report that generation from the GEM unit would only be 14

deemed RPS-eligible beginning in April of 2011. 15

SCE’s costs associated with registering and tracking renewable energy deliveries in WREGIS 16

include account fees, volumetric fees, and service fees for renewable power. SCE paid $70,157 in fees 17

during the Record Period. This amount included $270 for the retirement of certificates from May 2008 18

through December 2010, which were created as a result of late adjustments for that period. 19

5. RPS Insurance Verification 20

RPS projects generally are required to obtain and maintain comprehensive general liability 21

insurance during the terms of their power purchase contracts. The WES system is used to provide 22

automated tracking of the insurance coverage. During the Record Period, 285 RPS contracts were 23

subject to SCE’s insurance verification procedures, which may include checking to ensure that these 24

contracts have: 25

� Obtained the required insurance before their projects can be operated in parallel with the 26

SCE electrical system. 27

101

� Maintained insurance policies and insurance carriers that meet SCE’s requirements. 1

� Maintained adequate insurance coverage throughout the terms of their contracts. 2

Of the 31 projects for which SCE received certificates, 15 were determined in compliance with the 3

above requirements and 16 were pending. 4

102

XI. 1

CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO)-RELATED COSTS 2

A. Background 3

During the Record Period, SCE incurred approximately $1.1665 billion in CAISO-related costs. 4

In its role as grid manager, the CAISO recovers its costs from SCE and other market participants 5

through tariffs approved by the Federal Energy Regulatory Commission (FERC). CAISO-related costs 6

are numerous and, for the most part, unavoidable. Although SCE has been billed by the CAISO for 7

costs associated with scores of different CAISO charge types, these costs can be divided into three major 8

groups: (1) grid management and other operating charges; (2) the net cost of market-related expenses 9

and revenues (net market costs); and (3) FERC fees. 10

B. Grid Management Charges 11

Grid management and other operating charges (GMC) are assessed to market participants for the 12

purpose of recovering the CAISO’s operation and maintenance costs associated with control area 13

services, as described in various GMC codes in the CAISO tariff.57 These charges are levied by the 14

CAISO on a usage basis. SCE incurred approximately $57.2 million of GMC during the Record Period. 15

C. Net Market Costs 16

Net market costs are the sum of charges to SCE and the revenues received by SCE (excluding 17

FERC-jurisdictional SCE transmission system market revenues) associated with the CAISO’s various 18

markets, including: (1) ancillary services; (2) imbalance energy; (3) congestion, including the cost 19

incurred to acquire Congestion Revenue Rights (CRRs); (4) net energy costs; and (5) capacity revenues. 20

In this ERRA proceeding, SCE seeks a Commission determination that all of SCE’s CAISO-related 21

costs and least-cost dispatch (LCD)-related actions were consistent with SCE’s AB57 Long-Term 22

Procurement Plan (LTPP), including the Commission’s LCD mandate as memorialized in that Plan. 23

Because SCE managed its bundled customer procurement requirements and executed LCD on a 24

57 CAISO also charges SCE, on an annual basis, a percentage share of operating costs assessed by the Western Electricity

Coordinating Council. This charge is included with GMC.

103

portfolio-wide basis, this chapter and Chapter II includes testimony regarding all relevant costs and 1

practices for the Record Period. During the Record Period, the net CAISO market costs assessed to SCE 2

were approximately $1.0981 billion. The year-over-year increase, as compared to the 2011 Record 3

Period, is in part due to (1) the SONGS outages; and (2) fewer dispatchable units in SCE’s resource 4

portfolio. 5

SCE cannot separately and specifically identify the CAISO costs and LCD actions that resulted 6

from the SONGS outages, but it has estimated the costs associated with the outages in the SONGS 7

Outage Memorandum Account (OMA) established in I.12-10-013 (the SONGS OII). SCE-3 of this 8

ERRA filing reflects those estimates. 9

1. Ancillary Services Costs 10

Ancillary services (AS) consist of four distinct products: spinning reserve, non-spinning reserve, 11

regulation up, and regulation down. The CAISO determines the amount of AS required to provide for 12

regulation margin and operating reserves in a given CAISO load zone (e.g., the level of AS required to 13

serve load in zone SP-15 may be greater than in zone NP-15 due to transmission constraints or 14

differences in loads). Load serving entities (LSEs) are permitted by the CAISO to self-provide all, or a 15

portion of, required AS.58 When economic to do so, SCE elected to self-provide a portion of its AS 16

requirements. However, an LSE cannot avoid the CAISO’s imposition of AS requirements on the 17

LSE’s actual load obligation. As a result, all AS costs that SCE incurred during the Record Period 18

should be found reasonable. 19

2. Imbalance Energy Costs 20

Imbalance energy costs are the product of real-time electricity prices and supply/demand energy 21

differences at the CAISO’s metering points, either as a result of CAISO instructions (instructed energy) 22

or uninstructed energy imbalances. Uninstructed energy imbalances occur when actual generation levels 23

differ from awarded/instructed generation levels or when actual load differs from awarded load. 24

58 The absence of self-provision does not mean that SCE did not provide AS to CAISO markets. When not self-provided,

SCE bid its available AS capacity to the CAISO markets.

104

During 2012, SCE employed a combination of strategic bidding into CAISO markets and over-1

the-counter (OTC) transacting to minimize its exposure to the CAISO’s real-time energy market. 2

Imbalance energy costs incurred during the Record Period were largely the result of unavoidable 3

forecast errors or normal supply performance deviations and should be found reasonable. 4

3. Congestion Charges 5

Congestion charges occur when the energy scheduled over a given transmission path exceeds the 6

delivery capacity of the path (creating congestion), and the CAISO charges path participants a fee based 7

on the cost incurred to relieve such congestion. However, to the extent a path participant holds a 8

corresponding CRR, that participant receives an offset to its transmission congestion charge. During the 9

Record Period, SCE participated in CAISO auctions to acquire CRRs. These acquisitions were designed 10

to minimize CAISO congestion charges and are discussed in greater detail below. 11

a) CRR Costs 12

CRRs entitle the holder to the value associated with the cost to relieve grid congestion between a 13

source (electricity delivered to the CAISO grid) and a sink (electricity taken from the CAISO grid). 14

SCE uses CRRs as an important financial instrument to hedge the risk of congestion associated with its 15

portfolio of resources. The CAISO allocates and auctions CRRs on a quarterly and monthly basis. A 16

portion of seasonal CRRs can be converted to long-term (LT) CRRs with terms of 10 years. 17

During the Record Period, SCE acquired both near- and long-term CRRs, for which it was 18

assessed certain net costs (i.e., expenses less revenue) by the CAISO. Pursuant to Resolution E-4134, 19

SCE utilized an evaluation and selection process that adhered to the Commission-approved up-front 20

standards for the procurement of CRRs. Key to this evaluation and selection process is the 21

Commission’s requirement that CRRs be used as a tool to hedge congestion risk and not to speculate. 22

The Commission approved “only the acquisition of CRRs that closely resemble the LSE’s expected grid 23

usage both in the choice of source/sink combinations and in the duration of the CRR with respect to the 24

length of the LSE’s energy supply contracts.”59 SCE’s review and evaluation process accounted for 25 59 See Resolution E-4134, p. 7.

105

these requirements and ensured that all nominations were consistent with SCE’s expected use of the 1

grid. 2

Resolution E-4134 also requires that SCE utilize methods to value CRRs and quantify the 3

associated risks.60 SCE performed an internal evaluation and utilized a consultant to value the CRRs 4

and quantify the risk of the instrument. These data points were then utilized in SCE’s selection process. 5

Finally, as required by Resolution E-4134, SCE reviewed its CRR nominations with the 6

Commission’s Energy Division and SCE’s Procurement Review Group (PRG). Because SCE followed 7

the Commission’s CRR directives, the net ERRA-recordable CRR costs should be found reasonable. 8

4. Net Energy Bid Award Charges 9

Throughout 2012, SCE submitted energy supply and demand bids to the CAISO which complied 10

with LCD objectives. Following its daily bid evaluation process, the CAISO awarded bids to SCE and 11

other market participants offering energy at the most competitive prices. Details regarding these bid 12

awards are contained in SCE’s workpapers supporting Chapter II. Because costs and revenues 13

associated with these bid awards are the direct result of CAISO actions, net energy bid award charges 14

should be deemed reasonable. 15

5. Residual Unit Commitment (RUC) Capacity Bid Award Revenue 16

Revenues received by SCE during the Record Period, in conjunction with awards for RUC 17

capacity bids, are included in the Net Market Costs category. Like energy bid awards, these RUC-18

related revenues are also directly related to CAISO actions, and should therefore be deemed reasonable. 19

Details of such bid awards are also contained in SCE’s Chapter II workpapers. 20

D. SCE Peaker Cost Allocation Mechanism (CAM) Revenues 21

In D.09-03-031, the Commission directed that the costs and resource adequacy benefits of SCE’s 22

first four peaker units,61 which are owned and operated by SCE, shall be allocated to all benefiting 23

customers. During the Record Period, SCE estimated net revenues of approximately $2.6 million.62 24

60 Id., pp. 13-15.

106

E. FERC Fees 1

FERC fees are allocated to CAISO participants in accordance with the CAISO’s filed tariffs. 2

During the Record Period, SCE’s portion of these FERC fees amounted to approximately $5.2 million. 3

F. Transmission Loss Charges to Deliver LADWP Returned Energy 4

In SCE’s existing transmission contract with LADWP, SCE acts as LADWP’s scheduling 5

coordinator to deliver LADWP-owned energy through the CAISO-controlled grid to LADWP’s control 6

area (also referred to as LADWP wheeling). This wheeling contract pre-dates the CAISO market and 7

does not allow SCE to pass CAISO costs through to LADWP.63 As the scheduling coordinator for this 8

existing transmission contract, SCE submits hourly schedules on LADWP’s behalf and is billed by the 9

CAISO for real-time transmission losses at the CAISO rate. During the Record Period, these LADWP 10

wheeling costs amounted to $8.6 million. To reimburse SCE for these real-time transmission losses, 11

LADWP schedules return energy to SCE according to terms specified in the transmission contract. The 12

return energy value is calculated by SCE as the product of: (1) the energy quantity received from 13

LADWP; and (2) the CAISO Day-Ahead price at the Sylmar intertie. This return energy value is 14

credited to ERRA. 15

G. Reasonableness of SCE’s CAISO-Related Costs 16

The majority of CAISO-related costs incurred during the Record Period were unavoidable. 17

Those costs that SCE had discretion to control were managed consistent with Commission directives and 18

the objective of minimizing costs to bundled customers. Accordingly, all CAISO-related costs that SCE 19

Continued from the previous page 61 D.09-03-031 included only the first four SCE peakers (Barre, Center, Grapeland and Mira Loma). The fifth peaker

(McGrath) entered service on November 1, 2012, and the Commission has not yet ruled on its revenue allocation. 62 SCE also applied an offsetting revenue amount of approximately $3.9 million to the New System Generation Balancing

Account, representing the estimated net revenues from June 1, 2009 through December 31, 2011. 63 SCE previously requested FERC permission to pass these costs through to LADWP; FERC denied SCE’s request.

107

incurred during the Record Period, as shown in Table XI-27, should be found reasonable and compliant 1

with SCE’s LTPP. 2

Table XI-27 Total CAISO-Related Costs Incurred by SCE During the Record Period

(Million Dollars)

Category Cost GMC 57.2 Net Market Costs Peaker CAM Revenues

1,098.1 (2.6)

FERC Fees 5.2 LADWP Wheeling 8.6 Total 1,166.5

108

XII. 1

OPERATION OF RATEMAKING ACCOUNTS 2

A. Introduction 3

In this chapter, SCE sets forth for Commission review the operation of various regulatory 4

accounts (i.e., balancing and memorandum accounts).64 The majority of these accounts, such as the 5

Energy Resource Recovery Account (ERRA) Balancing Account, are audited by the Commission to 6

ensure that recorded entries are accurate and consistent with Commission decisions. These accounts are 7

set forth in Sections B-D of this chapter. SCE is not seeking to recover the amounts recorded in these 8

accounts since the review is being performed on an after-the-fact basis (i.e., SCE has already been 9

authorized to recover these expenses). For the accounts set forth in Section E of this chapter, SCE is 10

requesting authority to recover or refund the balances recorded in these accounts upon a Commission 11

finding in this proceeding that these costs and revenues are reasonable. In Section F, SCE provides an 12

overview of the Energy Settlements Memorandum Account, requests authority to refund the balance in 13

the memorandum account to customers, and also requests authority to recover the balance recorded in 14

the Litigation Costs Tracking Account. 15

Collectively, SCE is requesting a net revenue increase in 2014 of $4.998 million, including 16

franchise fees and uncollectibles (FF&U) associated with these four accounts. A summary of this 17

requested increase is shown in Table XII-28 below. 18

64 The detailed monthly operation for each account is included in the workpapers supporting this chapter.

109

Table XII-28 Summary of 2014 Revenue Requirement Change

($000)

This chapter is organized as follows: 1

� Section B sets forth the operation of the following regulatory accounts during the Record 2

Period:65 3

o ERRA Balancing Account 4

o Base Revenue Requirement Balancing Account (BRRBA) 5

o Nuclear Decommissioning Adjustment Mechanism (NDAM) 6

o Public Purpose Programs Adjustment Mechanism (PPPAM) 7

o CARE Balancing Account (CBA) 8

o New System Generation Balancing Account (NSGBA) 9

� Section C shows the operation of the following accounts, as required by Decisions 06-10

05-016, 09-03-025: and 12-11-051.66 11

o Medical Programs Balancing Account (MPBA) 12

o Pension Costs Balancing Account (PCBA) 13

o Post Employment Benefits Other Than Pensions Balancing Account (PBOP BA) 14

o Results Sharing Memorandum Account (RSMA) 15 65 The Commission reviews these accounts annually in SCE’s April ERRA Review proceeding. 66 The Mohave Balancing Account is presented for review in Chapter XV.

B a la nc ing/M e m o ra nd um A c c o unts R e ve nue C ha nge

L itiga tio n C o sts T ra c k ing A c c o unt 3 ,4 7 4 M a rk e t R e d e sign a nd T e c hno lo gy U p gra d e M A * 7 ,0 2 7 P ro je c t D e ve lo p m e nt D ivis io n M A (3 ,3 6 3 )P urc ha se A gre e m e nt A d m inis tra tio ns C o sts B A (2 ,1 9 6 )

T o ta l U nd e r- C o lle c tio n: 4 ,9 4 2 F F & U : 5 6

T o ta l R e ve nue R e q uire m e nt C ha nge : 4 ,9 9 8$ * M R T U is p r e se n t e d in C h a p t e r X I V.

110

� Section D shows the operation of the following account: 1

o Fuel Cell Program Memorandum Account (FCPMA) 2

� Section E shows the operation of the following accounts: 3

o Project Development Division Memorandum Account (PDDMA) 4

o Purchases Agreement Administrative Costs Balancing Account (PAACBA) 5

� Section F shows the operation of the Energy Settlements Memorandum Account (ESMA) 6

and Litigation Costs Tracking Account (LCTA), as required by Resolution E-3894. 7

The following Table XII-29 summarizes SCE’s requested action associated with the accounts 8

reviewed in this proceeding: 9

Table XII-29

The operations of the SmartConnect™ Balancing Account (ESCBA), the Market Redesign and 10

Technology Upgrade Memorandum Account (MRTUMA), and the Mohave Balancing Account (MBA) 11

are presented in other chapters of this proceeding. 12

Lin e N o . A C C O U N T R EVIEW

R EC O VER Y/R EF U N D

R EC O VER Y/ R EF U N D A M T 1 /

1 . ER R A YES2. B R R B A YES3. N D A M YES4. P P P A M YES5. C A R E B A YES6. N e w S y s t e m Ge n e ra t io n B A YES

7.En e rg y S e t t le m e n t s M A a n d Lit ig a t io n C o s t sT ra c kin g A c c o u n t YES YES $3.474 m illio n

8 . F u e l C e ll P ro g ra m M A YES9. M e d ic a l P ro g ra m s B A YES

10. P e n s io n C o s t s B A a n d P B O P B A YES11. P ro je c t D e v e lo p m e n t D iv is io n M A YES YES ($3.363) m illio n12 . P u rc h a s e s A g re e m e n t A d m in is t ra t iv e C o s t s B A YES YES ($2.196) m illio n13 . R e s u lt s S h a rin g M A YES14. S m a rt C o n n e c t ™ B A (C h a p t e r X III) YES15. M a rke t R e d e s ig n a n d T e c h n o lo g y U p g ra d e M A (C h a p t e r X IV) YES YES $7.027 m illio n16 . M o h a v e B A (C h a p t e r X V) YES

1/ D o e s n o t in c lu d e F F & U .

111

B. Operation of Balancing Accounts and Adjustment Mechanisms During the Record Period 1

1. Operation of the ERRA Balancing Account 2

The purpose of the ERRA Balancing Account is to record the difference between ERRA-related 3

revenue and SCE’s recorded fuel costs and purchased power-related expenses. Table XII-30 below 4

summarizes the operation of the ERRA Balancing Account during the Record Period. 5

Table XII-30 Operation of the ERRA

OP 2 of D.07-04-020 issued in Rulemaking 04-04-003 modified OP 25 of D.04-12-048 such that 6

effective April 12, 2007, SCE shall submit a detailed summary report each month to the Energy Division 7

showing the activity in the ERRA Balancing Account. In addition, SCE shall make available for the 8

Commission staff and interested parties all monthly invoices and supporting documentation in 9

L ine N o. D e s c r ip tion ($000)

1 . B e ginn ing B a la nc e (392 ,004)

2 . C o m m is s io n A u t h o rize d T ra n s fe rs3 . En e rg y S e t t le m e n t s M e m o ra n d u m A c c o u n t B a la n c e T ra n s fe r (Ja n u a ry ) (47 ,736) 4 . Lo n g T e rm P ro c u re m e n t P la n T e c h n ic a l A s s is t a n c e M e m o ra n d u m A c c o u n t T ra n s fe r (Ja n u a ry ) 28 5 . T o t a l A u t h o rize d T ra n s fe rs (47 ,707)

6 . S ig n ific a n t En t rie s / A d ju s t m e n t s (Gre a t e r t h a n $1 M illio n )7 . C a rry in g C o s t A d ju s t m e n t (F e b ru a ry & M a rc h ) (4 ,044) 8 . C a lp in e S u t t e r C A M A d ju s t m e n t (S e p t e m b e r) (2 ,022) 9 . P e a ke r C A M A d ju s t m e n t (O c t o b e r & N o v e m b e r) 6 ,166

10 . T o t a l S ig n ific a n t A d ju s t m e n t s 100

11 . O t h e r En t rie s / A d ju s tm e n t s12 . M o u n t a in v ie w A v a ila b ilit y In c e n t iv e A d ju s t m e n t (M a rc h ) 64 13 . LA D W P R e t u rn e d En e rg y A d ju s t m e n t (O c t o b e r) (623) 14 . T o t a l O th e r A d ju s t m e n t s (559)

15 . A d ju s t e d B e g in n in g B a la n c e (Lin e 1 + Lin e 5 + Lin e 10 + Lin e 14) (440 ,170)

16 . R e v e n u e (3 ,789 ,142) 17 . Exp e n s e 4 ,094 ,618

18 . (O v e r)/ U n d e r C o lle c t io n (Lin e 16+ Lin e 17) 305 ,475

19 . In t e re s t (770)

20 . T o t a l En d in g B a la n c e (Lin e 15 + Lin e 18 + Lin e 19) (135 ,464)

112

conjunction with the reports, at the request of the Commission or interested parties, in lieu of submitting 1

the monthly documentation to the Energy Division. 2

Below, SCE discusses the Commission decisions and significant adjustments (defined as $1 3

million or greater) impacting the recorded operation of the ERRA Balancing Account during the Record 4

Period, as shown in Table XII-30.67 5

a) Commission-Authorized Transfers 6

Pursuant to Advice Letter 1811-E-A and Resolution E-3894, the ESMA68 is reviewed in SCE’s 7

ERRA Review proceedings. In D.08-11-021, the Commission authorized SCE to transfer the December 8

31, 2011 credit balance of $47.736 million in the ESMA to the ERRA Balancing Account. As shown on 9

Line 3 of Table XII-30, SCE transferred this amount in January 2012. 10

Pursuant to SCE’s Preliminary Statement, Part N.51, Long-Term Procurement Plan Technical 11

Assistance Memorandum Account (LTAMA), SCE is authorized to transfer the year-end recorded 12

balance in the LTAMA to the ERRA on January 1 of each year. As shown on Line 4 of Table XII-30, 13

SCE transferred the December 31, 2011 recorded LTAMA debit balance of $0.028 million to the ERRA 14

on January 1, 2012. The operation of the LTAMA is set forth in SCE’s Advice Letter 2241-E.69 15

b) Significant Adjustments 16

SCE recorded the following significant (greater than $1 million) adjustments in the ERRA 17

during the Record Period. 18

In February and March 2012, SCE recorded Carrying Cost Interest Rate credit adjustments 19

totaling $4.044 million for the period of January 2010 through December 2011, as shown on Line 7 of 20

Table XII-30. In March 2009, SCE issued $250 million in fixed rate (4.15%) notes to finance fuel 21

inventory. Additionally, in October 2011, SCE issued a $150 million floating rate note; floating rate is 22

67 Although this testimony discusses only significant adjustments, support for every adjustment during the Record Period is

included in SCE’s workpapers.

68 Advice Letter 1811-E-A was approved by the Commission’s Energy Division with an effective date of November 29, 2004.

69 Advice Letter 2241-E was approved by the Commission’s Energy Division with an effective date of June 18, 2008.

113

based on 3 month LIBOR70 + 45 basis points, payable quarterly. Due to the issuance of the additional 1

notes, the Fuel Inventory Interest Rate changed from 4.15% to a blended rate. To reflect the rate 2

change, adjustment entries were recorded in February and March 2012. 3

Pursuant to Resolution E-4471,71 Calpine Sutter Cost Allocation Mechanism (CAM) energy 4

costs are authorized to record in the New System Generation Balancing Account (NSGBA). As shown 5

on Line 8 of Table XII-30, SCE recorded a Calpine Sutter CAM energy adjustment in September 2012. 6

The credit adjustment of $2.022 million was to reclass July 2012 CAM costs from ERRA to NSGBA. 7

In October and November 2012, as shown on Line 9 of Table XII-30, SCE recorded Peaker 8

CAM energy adjustments. The debit adjustments of $6.166 million per D.09-03-03172 and Advice 9

Letter 2346-E73 were recorded to reclass June 2009 through October 2012 CAM costs from the NSGBA 10

to ERRA. 11

c) Costs 12

Starting in November 2012, Greenhouse Gas (GHG) Compliance Instrument Transaction costs 13

were recorded in ERRA, per OP 10 of D.12-04-045. In the Long Term Procurement Plan (LTPP), SCE 14

and other utilities maintained it was necessary to procure greenhouse gas compliance instruments in 15

order to comply with the new cap-and-trade program implemented by the California Air Resources 16

Board. In compliance with D.12-04-045, SCS filed Advice Letter 2795-E which was approved by the 17

Commission, effective November 12, 2012. During the 2012 Record Period, $40.961 million was 18

recorded in ERRA.�19

2. Operation of the BRRBA 20

The purpose of the BRRBA is to record the difference between BRRBA-related revenue and 21

Commission-authorized base distribution and generation revenue requirements. The Commission 22

70 LIBOR represents the “London Interbank Offered Rate.” 71 Resolution E-4471 was adopted on March 22, 2012. 72 Decision 09-03-031 was adopted on March 26, 2009. 73 Advice Letter 2346-E was approved by the Commission’s Energy Division with an effective date of June 1, 2009.

114

established the BRRBA in its decision in Phase 1 of SCE’s 2003 GRC, D.04-07-022. SCE implemented 1

the BRRBA through Advice Letter 1808-E and the Commission adopted the BRRBA in Resolution E-2

3895, effective July 1, 2004. The BRRBA includes distribution and generation sub-accounts to track 3

under-collections and over-collections by function.74 4

Table XII-31 below summarizes the operation of the BRRBA during the Record Period.5

74 Amounts recorded in the distribution sub-account are recovered from both bundled service and direct access customers,

while amounts recorded in the generation sub-account are recovered from bundled service customers only.

115

Table XII-31 Operation of the BRRBA

L in eN o . D e sc r ip t io n ( $ 0 0 0 )1 . B e gin n in g B a la n c e 1 2 0 ,4 6 9

2 . C o m m issio n A ut h o r iz e d T r a n sf e r s3 . 2 0 1 1 P ur c h a se A gr e e m e n t A dm in ist r a t iv e C o st s B a la n c in g A c c o un t I n t e r e st T r a n sf e r ( Ja n ua r y ) ( 3 ) 4 . 2 0 1 1 D e m a n d R e sp o n se P r o gr a m B a la n c in g A c c o un t I n t e r e st T r a n sf e r ( Ja n ua r y ) ( 1 0 2 ) 5 . 2 0 1 1 B a la n c e A f f ilia t e T r a n sf e r F e e M e m o A c c o un t T r a n sf e r ( Ja n ua r y ) ( 3 8 1 ) 6 . 2 0 1 1 B a la n c e P e n sio n C o st s B a la n c in g A c c o un t T r a n sf e r ( Ja n ua r y ) 2 3 ,1 5 3 7 . 2 0 1 1 B a la n c e P o st E m p lo y m e n t B e n e f it s O t h e r T h a n P e n sio n s C o st s B a la n c in g A c c o un t T r a n sf e r ( Ja n ua r y ) ( 1 8 ,8 7 0 ) 8 . 2 0 1 1 B a la n c e M e dic a l P r o gr a m s B a la n c in g A c c o un t T r a n sf e r ( Ja n ua r y ) 5 ,7 4 0 9 . 2 0 0 1 B a la n c e P a lo Ve r de B a la n c in g A c c o un t T r a n sf e r ( Ja n ua r y ) ( 4 0 ,8 3 0 )

1 0 . 2 0 1 1 R e sult s Sh a r in g M e m o A c c o un t T r a n sf e r ( Ja n ua r y ) ( 4 ) 1 1 . 2 0 1 1 M o h a v e B a la n c in g A c c o un t T r a n sf e r ( Ja n ua r y ) ( 2 ,2 2 5 ) 1 2 . E le c t r ic D e f e r r e d R e f un d A c c o un t T r a n sf e r ( M a r c h ) ( 7 ,9 0 8 ) 1 3 . F e de r a l E n e r gy R e gula t o r y C o m m issio n R e f un d ( M a y ) ( 1 0 ,2 7 2 ) 1 4 . 2 0 1 2 - 2 0 1 4 D e m a n d R e sp o n se P r o gr a m A ut h o r iz e d R e v e n ue T r ue - up ( M a y ) ( 5 ,7 2 8 ) 1 5 . SO N GS 2 & 3 Se ism ic P r o je c t s M e m o A c c o un t T r a n sf e r ( SSP M A ) ( Jun e ) 1 ,1 0 1 1 6 . 2 0 1 1 H a z a r do us Subst a n c e C le a n up & L it iga t io n C o st B a la n c in g A c c o un t T r a n sf e r ( Se p t e m be r ) 6 ,4 2 8 1 7 . 2 0 0 9 - 2 0 1 1 C E M A B a r k B e e t le ( N o v e m be r ) 1 1 ,7 5 3 1 8 . A ir R e so ur c e B o a r d F e e s M e m o r a n dum A c c o un t T r a n sf e r ( N o v e m be r ) 4 ,9 3 8 1 9 . 2 0 1 2 Ge n e r a l R a t e C a se - N o n - U t ilit y A f f ilia t e T r ue - U p ( N o v e m be r ) ( 5 1 ) 2 0 . 2 0 1 2 Ge n e r a l R a t e C a se - GR C M e m o A c c o un t T r a n sf e r ( N o v e m be r ) 3 8 8 ,8 4 9 2 1 . 2 0 1 2 Ge n e r a l R a t e C a se - F F & U T r ue - up ( N o v e m be r ) ( 3 ,1 3 4 ) 2 2 . 2 0 1 2 Ge n e r a l R a t e C a se - R e m o v a l o f SO N GS R e f ue lin g ( Ja n & F e b) ( N o v e m be r ) ( 5 0 ,7 8 8 ) 2 3 . 2 0 1 2 Ge n e r a l R a t e C a se - F o ur C o r n e r s M e m o r a n dum A c c o un t ( N o v e m be r ) 2 ,3 1 6 2 4 . 2 0 1 2 Ge n e r a l R a t e C a se - So la r P h o t o v o lt a ic P r o gr a m B a la n c in g A c c o un t ( N o v e m be r ) ( 4 ,5 4 3 ) 2 5 . 2 0 1 2 Ge n e r a l R a t e C a se - F ue l C e ll P r o gr a m M e m o A c c o un t ( N o v e m be r ) ( 4 6 3 ) 2 6 . 2 0 1 2 Ge n e r a l R a t e C a se - So la r P V A ut h o r iz e d R e v e n ue R e quir e m e n t T r ue - up ( D e c e m be r ) ( 2 9 ,3 4 2 ) 2 7 . 2 0 1 2 Ge n e r a l R a t e C a se - F ue l C e ll P r o gr a m M e m o A c c o un t ( D e c e m be r ) ( 5 8 7 ) 2 8 . 2 0 1 2 Ge n e r a l R a t e C a se - N o n - D isc r e t io n a r y Se r v ic e s M e m o A c c o un t T r a n sf e r 1 2 4 2 9 . 2 0 0 7 - 2 0 1 1 C E M A F ir e st o r m T r a n sf e r ( D e c e m be r ) 7 ,9 7 5 3 0 . P ur c h a se A gr e e m e n t A dm in ist r a t iv e C o st s C a p a c it y C o n t r a c t s ( M o n t h ly ) 1 6 ,8 3 4 3 1 . Sm a r t C o n n e c t ™ B a la n c in g A c c o un t ( M o n t h ly ) 1 7 9 ,2 6 6 3 2 . SO N GS 2 & 3 St e a m Ge n e r a t o r R e p la c e m e n t B a la n c in g A c c o un t ( M o n t h ly ) 1 2 0 ,6 4 7 3 3 . SO N GS 2 & 3 St e a m Ge n e r a t o r R e m o v a l & D isp o sa l B a la n c in g A c c o un t ( M o n t h ly ) ( 1 ,3 6 4 ) 3 4 . So la r P h o t o v o lt a ic P r o gr a m B a la n c in g A c c o un t ( M o n t h ly ) 5 0 ,2 1 5 3 5 . T o t a l C o m m issio n A ut h o r iz e d T r a n sf e r s 6 4 2 ,7 4 3

3 6 . O t h e r E n t r ie s/A djust m e n t s3 7 . R e c la ssif ic a t io n o f D e m a n d R e sp o n se P r o gr a m B a la n c in g A c c o un t E x p e n se s t o B R R B A ( Ja n ua r y ) 1 ,0 5 3 3 8 . Sm a r t C o n n e c t ™ B a la n c in g A c c o un t A djust m e n t ( Ja n ua r y ) ( M a r c h ) ( N o v e m be r ) ( D e c e m be r ) 1 ,9 3 0 3 9 . So la r P h o t o v o lt a ic P r o gr a m B a la n c in g A c c o un t A djust m e n t ( Ja n ua r y ) ( M a r c h ) ( July ) ( D e c ) 1 ,3 5 7 4 0 . SO N GS 2 & 3 St e a m Ge n e r a t o r R e p la c e m e n t B a la n c in g A c c o un t ( SGR B A ) ( Ja n ua r y ) ( M a r c h ) ( D e c e m be r ) 1 1 5 4 1 . SO N GS 2 & 3 St e a m Ge n e r a t o r R e m o v a l & D isp o sa l B a la n c in g A c c o un t ( SGR A D B A ) ( D e c e m be r ) ( 6 2 6 ) 4 2 . R a t e o f R e t ur n A djust m e n t f o r C a p it a l- R e la t e d B a la n c in g A c c o un t s ( M a y ) ( 9 ,5 9 5 ) 4 3 . T o t a l O t h e r A djust m e n t s ( 6 ,8 1 8 )

4 4 . A djust e d B e gin n in g B a la n c e ( L in e 1 + L in e 3 5 + L in e 4 3 ) 7 5 6 ,3 9 4 4 5 . R e v e n ue s ( 5 ,6 3 9 ,3 7 9 ) 4 6 . E x p e n se s 5 ,3 8 7 ,8 4 2 4 7 . ( O v e r ) /U n de r C o lle c t io n ( L in e 4 5 + L in e 4 6 ) ( 2 5 1 ,5 3 7 )

4 8 . I n t e r e st 4 1 3 4 9 . E n din g B a la n c e ( L in e 4 4 + L in e 4 7 + L in e 4 8 ) 5 0 5 ,2 6 9

116

The following testimony discusses the Commission decisions and significant adjustments 1

reflected in the BRRBA during the Record Period. 2

a) Commission Authorized Transfers 3

Pursuant to Preliminary Statement, Part L, Purchase Agreement Administrative Costs Balancing 4

Account (PAACBA), as authorized by D.08-03-017 and Advice Letter 2243-E,75 annual interest is 5

calculated when the average balance in the PAACBA is an under-expended amount. SCE is required to 6

return annual interest to customers by transferring such amounts to the distribution sub-account of the 7

BRRBA. As shown on Line 3 of Table XII-31, in January 2012 SCE transferred the December 31, 2011 8

annual interest credit balance of $0.003 million recorded in the PAACBA to the distribution sub-account 9

of the BRRBA. 10

Pursuant to Preliminary Statement, Part Y, Demand Response Program Balancing Account 11

(DRPBA), as authorized by D.06-03-024 and Advice Letter 1985-E,76 annual interest is calculated when 12

the average balance in the DRPBA is an under-expended amount. SCE is required to return annual 13

interest to customers by transferring such amounts to the distribution and generation sub-account of the 14

BRRBA. As shown on Line 4 of Table XII-31, SCE transferred the December 31, 2011 annual interest 15

credit balance of $0.102 million recorded in the DRPBA to the BRRBA in January 2012. 16

Pursuant to Preliminary Statement, Part YY, BRRBA, Section 4.A.10.f., SCE is authorized to 17

transfer amounts recorded in the Affiliate Transfer Fee Memorandum Account (ATFMA) to the 18

distribution sub-account of the BRRBA on an annual basis. As shown on Line 5 of Table XII-31, SCE 19

transferred the December 31, 2011 credit balance of $0.381 million recorded in the ATFMA to the 20

BRRBA in January 2012.77 21

75 Advice Letter 2243-E was approved by the Commission’s Energy Division with an effective date of June 13, 2008. 76 Advice Letter 1985-E was approved by the Commission’s Energy Division with an effective date of April 14, 2006. 77 Amounts recorded in the ATFMA reflect transfer fees received by SCE from covered affiliates when an employee of

SCE is transferred, assigned or otherwise employed by the affiliate pursuant to Appendix A, Rule V.G.2.c of D.97-12-088 and as modified by D.98-08-035.

117

Pursuant to D.09-03-02578 and Advice Letter 2336-E79 and Preliminary Statement, Part OO, 1

Pension Costs Balancing Account (PCBA), SCE is authorized to transfer the December 31 balance 2

recorded in the PCBA each year to the BRRBA. As shown on Line 6 of Table XII-31, the January 2012 3

amount of $23.153 million reflects the year-end 2011 debit balance transfer from the PCBA. 4

Pursuant to D.09-03-025 and Advice Letter 2336-E80 and Preliminary Statement, Part PP, Post-5

Employment Benefits Other Than Pensions (PBOP) Costs Balancing Account, SCE is authorized to 6

transfer the December 31 balance recorded in the PBOP each year to the BRRBA. As shown on Line 7 7

of Table XII-31, the January 2012 amount of $18.870 million reflects the year-end 2011 credit balance 8

transfer from the PBOP. 9

Per D.09-03-025, Advice Letter 2336-E,81 and Preliminary Statement, Part VV, Medical 10

Programs Balancing Account (MPBA), SCE is authorized to transfer the December 31 balance recorded 11

in the MPBA each year to the BRRBA. As shown on Line 8 of Table XII-31, the January 2012 amount 12

of $5.740 million reflects the year-end 2011 debit balance transfer from the MPBA. 13

Pursuant to D.09-03-025 and Advice Letter 2336-E82 and (former) Preliminary Statement J, the 14

Palo Verde Balancing Account (PVBA), SCE is authorized to transfer the December 31 balance 15

recorded in the PVBA each year to the generation sub-account of the BRRBA. As shown on Line 9 of 16

Table XII-31, the January 2012 transfer amount of $40.830 million reflects the year-end 2011 credit 17

balance transfer from the PVBA. 18

Pursuant to D.06-05-016 and Preliminary Statement, Part N.8 Memorandum Accounts - Results 19

Sharing Memorandum Account (RSMA), SCE is authorized to transfer the December 31, 2011 credit 20

balance in the RSMA to the distribution and generation sub-accounts of the BRRBA. As shown on Line 21

78 SCE’s 2009 GRC Decision D.09-03-025, effective January 1, 2009. 79 Advice Letter 2336-E was approved by the Commission’s Energy Division with an effective date of March 30, 2009. 80 Id. 81 Advice Letter 2336-E was approved by the Commission’s Energy Division with an effective date of March 30, 2009. 82 Id.

118

10 of Table XII-31, in January 2012, SCE recorded the credit balance of $0.004 million to reflect the 1

year-end 2011 balance transfer from the RSMA. 2

Pursuant to Advice Letter 2003-E83 and Preliminary Statement, Part NN, Mohave Balancing 3

Account (MBA), SCE is authorized to transfer the December 31 balance recorded in the MBA each year 4

to the generation sub-account of the BRRBA. As shown on Line 11 of Table XII-31, the January 2012 5

amount of $2.225 million reflects the year-end 2011 credit balance transfer from the MBA. 6

In D.99-09-070, SCE was authorized to transfer the customers’ share of its other operating 7

revenue (OOR) associated with non-tariff products and services to the Electric Deferred Refund 8

Account (EDRA) on an annual basis. These amounts are initially recorded in the Gross Revenue 9

Sharing Mechanism (GRSM), Preliminary Statement, Part G, and then transferred to the EDRA. As 10

shown on Line 12 of Table XII-31, and pursuant to Advice Letter 2546-E,84 SCE recorded a credit entry 11

of $7.908 million to reflect the transfer of the December 31, 2011 balance recorded in the EDRA. 12

Pursuant to Federal Energy Regulatory Commission (FERC) decisions regarding Docket Nos. 13

ER09-187-000, ER09-187-001 and ER10-160-000, SCE provided retail customer refunds for 14

overcollections accrued from January 1, 2009 through December 31, 2010 (Refund Period). Per Advice 15

Letter 2741-E,85 SCE recorded the refund in the distribution sub-account of the BRRBA. As shown on 16

Line 13 of Table XII-31, SCE recorded a credit entry of $10.272 million to reflect the FERC refund in 17

the distribution sub-account of the BRRBA. 18

SCE’s authorized funding for Demand Response programs for years 2012 through 2014 was set 19

forth in D.12-04-045, D.11-11-002 and Advice Letter 2739-E.86 In May, SCE adjusted the 2012 20

Demand Response Program authorized revenue requirement from January through April 2012. As 21

83 Advice Letter 2003-E was approved by the Commission’s Energy Division with an effective date of May 22, 2006. 84 Advice Letter 2546-E was approved by the Commission’s Energy Division with an effective date of February 26, 2011. 85 Advice Letter 2741-E was approved by the Commission’s Energy Division with an effective date of May 31, 2012. 86 Advice Letter 2739-E and -EA was approved by the Commission’s Energy Division with an effective date of May 25,

2012.

119

shown on Line 14 of Table XII-31, SCE recorded a total credit balance of $5.728 million to the 1

BRRBA. 2

Advice Letter 2658-E87 established the SONGS 2&3 Seismic Projects Memorandum Account 3

(SSPMA) to record SCE’s 78.21% share of the incremental costs associated with the SONGS 2&3 4

seismic projects prior to CPUC approval of SCE’s A.11-04-006. In D.12-05-004 and Advice Letter 5

2735-E88 SCE was granted the authority to record and recover actual costs of implementing the SONG 6

2&3 seismic activities in the BRRBA generation sub-account up to $50.1 million. As shown on Line 15 7

of Table XII-31, in June SCE transferred the ending debit balance of $1.101 million in the SONGS 2&3 8

SPMA to the generation sub-account of the BRRBA. 9

The Hazardous Substance Cleanup and Litigation Cost (HSCLC) Recovery Mechanism allocates 10

the costs and insurance proceeds associated with cleaning up certain properties contaminated with 11

hazardous substances between SCE customers and shareholders. The Commission established the 12

HSCLC Balancing Account to record customers’ share of hazardous substance cleanup costs and 13

insurance recoveries. On June 1 of each year, SCE files a report with the Commission’s Energy 14

Division identifying the costs and recoveries recorded in the HSCLC Balancing Account for the twelve-15

month period from April 1 through March 31. Ninety days after filing the annual report, SCE is 16

authorized to transfer the HSCLC balance to the appropriate ratemaking account for disposition. 17

Therefore, on September 1 of each year, SCE transfers the reviewed balance in the HSCLC Balancing 18

Account to the distribution sub-account of the BRRBA. As shown on Line 16 of Table XII-31, SCE 19

transferred a debit balance of $6.428 million recorded in the HSCLC Recovery Mechanism to the 20

BRRBA. The Commission reviewed this amount in SCE’s 2012 Annual Hazardous Waste Report.89 21

Pursuant to D.12-11-041, SCE is authorized to recover the January 1, 2009 through December 22

31, 2011 expenses of $11.735 million recorded in the Bark Beetle Catastrophic Events Memorandum 23

87 Advice Letter 2658-E was approved by the Commission’s Energy Division with an effective date of November 22, 2011. 88 Advice Letter 2735-E was approved by the Commission’s Energy Division with an effective date of June 22, 2012. 89 This review period is April 1, 2011 through March 31, 2012.

120

Account (CEMA) O&M cost sub-account (Bark Beetle CEMA). As shown on Line 17 of Table XII-31, 1

the debit amount of $11.753 million reflects the 2011 balance transfer with interest from the Bark Beetle 2

CEMA. 3

A.10-08-002 was jointly filed by the IOU’s to request authority to recover the costs of the Air 4

Resource Board’s AB 32 Implementation Fee from customers. D.10-12-026 authorized the creation of 5

memorandum accounts to record associated costs. Pursuant to D.12-10-044,90 SCE is authorized to 6

transfer the ending balance in the Air Resource Board Fees Memorandum Account (ARBFMA) to the 7

generation sub-account of the BRRBA. As shown on Line 18 of Table XII-31, in November the debit 8

amount of $4.938 million reflects the ending balance transfer with interest from the ARBFMA. 9

Pursuant to D.12-11-051 and Advice Letter 2826-E91 authorizing SCE’s 2012 General Rate Case 10

Phase I, in November 2012, SCE recorded the following adjustments and transfers effective January 1, 11

2012 to the BRRBA: 12

� An adjustment to reflect the difference between the authorized 2012 Non-Utility Affiliate 13

expenses and those recorded from January through October 2012. As shown on Line 19 of 14

Table XII-31, SCE recorded a credit balance adjustment of $0.051 million to the BRRBA. 15

� As shown on Line 20 of Table XII-31, SCE transferred the General Rate Case Memorandum 16

Account to the BRRBA for a total debit transfer of $388.849 million. 17

� An adjustment to reflect the difference between the authorized 2012 GRC Franchise Fees and 18

Uncollectibles (FF&U) rates and FF&U rates recorded from January through October 2012. 19

As shown on Line 21 of Table XII-31, SCE recorded a credit balance adjustment of $3.134 20

million to the BRRBA. 21

� As shown on Line 22 of Table XII-31, SCE removed the SONGS Refueling authorized 22

revenues for January and February 2012 from the BRRBA for a total credit balance of 23

$50.788 million. 24

90 D.12-10-044, OP 1. 91 Advice Letter 2826-E was approved by the Commission’s Energy Division with an effective date of December 19, 2012.

121

� As shown on Line 23 of Table XII-31, SCE transferred authorized Four Corners 1

Memorandum Account (FCMA) expenses through 2011 with interest from the FCMA to the 2

BRRBA, for a total debit transfer of $2.316 million. 3

� The Solar Photovoltaic Program Balancing Account (SPVPBA) is revised to reflect the 4

Commission adopted forecast. As shown on Line 24 of Table XII-31, SCE transferred the 5

SPVPBA credit adjustment of $4.543 million from the SPVPBA to the BRRBA. 6

� The Fuel Cell Program Memorandum Account (FCPMA) is revised to reflect the 7

Commission-adopted-O&M related forecast. As shown on Line 25 of Table XII-31, SCE 8

transferred the FCPMA credit adjustment of $0.463 million from the FCPMA to the 9

BRRBA. 10

� The SPVPBA is revised to reflect the Commission adopted revenue requirement of $36.194 11

million. As shown on Line 26 of Table XII-31, SCE transferred the SPVPBA credit 12

adjustment of $29.342 million from the SPVPBA to the BRRBA. 13

� The FCPMA is revised to reflect the Commission adopted capital related forecast. As shown 14

on Line 27 of Table XII-31, SCE transferred the FCPMA credit adjustment of $0.587 million 15

from the FCPMA to the BRRBA. 16

� The Non-Discretionary Services Memo Account was eliminated and the remaining balance 17

was transferred to the BRRBA. As shown on Line 28 of Table XII-31, SCE transferred the 18

ending debit balance of $0.124 million from the Non-Discretionary Service Memo Account 19

to the BRRBA. 20

The Commission in D.11-07-035 authorized a settlement agreement between SCE and the 21

Division of Ratepayer Advocates (DRA). As shown on Line 29 of Table XII-31, SCE is authorized to 22

transfer the settlement agreement debit balance of $7.975 million recorded in the Wind and Firestorm 23

CEMA. 24

122

In accordance with Advice Letter 2243-E92 and D.08-03-017, Preliminary Statement, Part L, the 1

PAACBA was established to record SCE’s administrative costs associated with managing the Demand 2

Response Capacity Purchase Agreement. SCE records actual capacity payments associated with the 3

approved PAACBA-related third-party demand response resource contracts on a monthly basis in the 4

BRRBA. As shown on Line 30 of Table XII-31, during the Record Period SCE recorded a total debit 5

amount of $16.834 million of PAACBA-related capacity payments to the distribution sub-account of the 6

BRRBA. 7

Pursuant to D.08-09-039 and Preliminary Statement, Part QQ, SmartConnect™ Balancing 8

Account (ESCBA), Section 2.d., SCE is authorized to transfer amounts recorded in the ESCBA to the 9

distribution sub-account of the BRRBA each month. As shown on Line 31 of Table XII-31, during the 10

Record Period SCE transferred a total debit amount of $179.266 million to the BRRBA. As shown on 11

Line 38, SCE also recorded a total debit adjustment of $1.930 million to the BRRBA to correct various 12

entries recorded in the ESCBA, bringing the ESCBA debit amount total to $181.196 million. 13

Pursuant to D.05-12-040 and Advice Letter 2355-E,93 SCE is authorized to transfer amounts 14

recorded in the SGRBA to the generation sub-account of the BRRBA each month. As show on Line 32 15

of Table XII-31, SCE transferred a debit balance of $120.647 million recorded in the SGRBA during the 16

Record Period to the generation sub-account of the BRRBA. As shown in Line 40, SCE also recorded a 17

total debit adjustment of $0.115 million to the BRRBA to correct various entries recorded in the 18

balancing account, bringing the SGRBA debit amount total to $120.762 million. 19


recorded in the SGRADBA to the generation sub-account of the BRRBA each month. As shown on 21

Line 33 of Table XII-31, SCE transferred a credit balance of $1.364 million recorded in the SGRADBA 22

during the Record Period to the generation sub-account of the BRRBA. As shown on Line 41, SCE also 23

92 Advice Letter 2243-E was approved by the Commission’s Energy Division with an effective date of June 13, 2008. 93 Advice Letter 2355-E was approved by the Commission’s Energy Division with an effective date of June 30, 2009. 94 Advice Letter 2355-E was approved by the Commission’s Energy Division with an effective date of July 30, 2009.

123

recorded a total credit of $0.626 million to the BRRBA to correct various entries recorded in the 1

balancing account, bringing the SGRADBA credit amount total to $1.990 million. 2


recorded in the SPVPBA to the generation sub-account of the BRRBA each month. As shown on Line 4

34 of Table XII-31, SCE transferred a debit balance of $50.215 million recorded in the SPVPBA during 5

the Record Period to the generation sub-account of the BRRBA. As shown on Line 39, SCE also 6

recorded a total debit adjustment of $1.357 million to the BRRBA to correct various entries recorded in 7

the balancing account, bringing the SPVPBA debit amount total to $51.572 million. 8


An adjustment was recorded in January 2012 to include Demand Response Contracts Energy 10

Payments inadvertently recorded to the Demand Response Balancing Account. As shown on Line 37 of 11

Table XII-31, SCE recorded a debit of $1.053 million to the BRRBA to properly reflect these expenses 12

as Demand Response Capacity contract costs and not Demand Response program expenses. 13

A rate of return adjustment was recorded in May 2012 to correct an error in the calculation of the 14

rate of return adopted in the 2008 Cost of Capital decision (D.07-12-049) from 8.75% to 8.74%. 15

Corrections were made to various accounting mechanisms and recorded to the BRRBA. As shown on 16

Line 42 of Table XII-31, SCE recorded a credit adjustment of $9.595 million to the BRRBA. 17

There were no other significant adjustments or Commission decisions impacting the recorded 18

operation of the BRRBA during the Record Period. 19

3. Operation of the NDAM 20

The Nuclear Decommissioning Adjustment Mechanism (NDAM) records the difference between 21

NDAM-related revenue and certain authorized and recorded costs associated with SCE’s ownership 22

share of San Onofre Nuclear Generating Station (SONGS) and Palo Verde Nuclear Generating Station 23

(Palo Verde). For the Record Period, amounts recorded in the NDAM include the authorized amount to 24

95 Advice Letter 2363-E was approved by the Commission’s Energy Division with an effective date of June 18, 2009.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

fund the

addition,

share of a

issues. A

special tr

$22.990 m

Period.

T

Record P

T

operation

2737-E r

authorize

96 D.10-0

Nuclear Dec

D.10-07-04

amounts pai

As a result of

ransfer from

million. Tab

a)

There were n

Period.

b)

There were n

n of the NDA

reduced NDT

ed NDTF fun

07-047, Conclu

commissioni

4796 authoriz

d to an indep

f the approva

the Nonqua

ble XII-32 b

Commissi

o significant

Significan

o significant

AM during th

TF authorize

nding is incl

usion of Law 2

ing Trust Fu

zed the modi

pendent pan

al of Advice

alified to the

below summa

TabOperatio

on-Authoriz

t transfers im

nt Adjustmen

t adjustment

he Record P

ed funding fr

luded in Line

21.

124

und (NDTF)

fication of th

nel for its rep

e Letter 2639

Qualified T

arizes the op

ble XII-32on of the ND

zed Transfers

mpacting the

nts

ts or Commi

Period. As d

rom $23.846

e 3 of Table

and recorde

he NDAM to

port associate

9-E and Adv

Trust, reducin

peration of th

DAM

s

e recorded op

ssion decisio

escribed abo

6 to $22.990

XII-32.

ed spent nucl

o allow for t

ed with nucl

vice Letter 27

ng authorize

he NDAM d

peration of th

ons impactin

ove, Advice

million. Re

lear fuel exp

the recovery

lear decomm

736-E, SCE

ed NDTF rev

during the Re

he NDAM d

ng the record

Letters 2639

eduction of t

penses. In

y of SCE’s

missioning

completed a

venues to

ecord

during the

ded

9-E and

the

a

125

4. Operation of the PPPAM 1

The Public Purpose Programs Adjustment Mechanism (PPPAM) records the difference between 2

PPPAM-related revenue and amounts authorized by the Commission for recovery through the Public 3

Purpose Programs Charge (PPPC). The amounts authorized by the Commission include funding for the 4

Electric Program Investment Charge (EPIC) to fund Research, Development and Demonstration 5

(RD&D) programs, energy efficient programs, low income energy efficiency and authorized CARE97 6

programs, and cool center and intervenor compensation costs. Table XII-33 below summarizes the 7

operation of the PPPAM during the Record Period. 8

Order Instituting Rulemaking (R.)11-10-003 was issued to address the termination of the 9

legislatively mandated Public Goods Charge CEC-administered Renewables and RD&D funding in two 10

phases. At the conclusion of Phase 1, the Commission adopted D.11-12-035 on December 15, 2011 and 11

required the IOUs to maintain the 2011 PGC funding levels for both the Renewable and RD&D 12

programs in 2012 on an interim basis until a final Phase 2 decision was issued. The Commission 13

established the EPIC funding mechanism to continue collecting the same level of funds previously 14

authorized for the CEC-related Renewables and RD&D programs through the PPPAM. In D.11-12-038, 15

IOUs were authorized to backfill the expiring PGC EE funding for 2012 with the Procurement EE funds, 16

resulting in no change in the total 2012 EE funding. The PGC sub-account of the PPPAM was 17

eliminated and the remaining balance transferred to the CPUC sub-account of the PPPAM. On May 24, 18

2012, the Commission adopted D.12-05-037 in Phase 2 of R.11-10-003 which confirmed the 19

continuation of the EPIC funding for 2012 at 2011 levels and set forth guidelines for the EPIC program 20

through 2020. Authorized revenues were divided between the CEC, SCE, and an administrative fee for 21

the CPUC. SCE issued Advice Letter 2747-E to set forth the new balancing account mechanisms.98 22

In addition, the Commission adopted D.12-08-044 establishing the authorized revenue 23

requirements for the Energy Savings Assistance Program (ESAP) (formerly referred to as Low Income 24

97 California Alternate Rates for Energy, a discount program for low income customers. 98 Advice Letter 2747-E was approved by the Commission’s Energy Division with an effective date of June 25, 2012.

1

2

3

4

5

6

7

8

9

10

11

12

13

Energy E

for 2012

changes.

B

operation

A

debit bala

Part FF, P

recorded

T

operation

Efficiency (L

through 201

Below SCE d

n of the PPPA

a)

As shown on

ance of $54.

PPPAM, 3.1

in the CBA

b)

There were n

n of the PPPA

LIEE)), Cool

14. The 201

discusses Co

AM during t

Commissi

Line 3 of Ta

.293 million

12. As expla

to the PPPA

Significan

o significant

AM during t

l Center, and

2 ESA and C

TOperat

mmission de

the Record P

on-Authoriz

able XII-33,

recorded in

ained below

AM on an an

nt Adjustmen

t adjustment

the Record P

126

d California A

CARE autho

Table XII-3tion of the P

ecisions and

Period.

zed Transfers

in January 2

the CBA to

in Section 5

nnual basis.

nts

ts or Commi

Period.

Alternate Ra

orized revenu

33 PPPAM

d significant

s

2012 SCE tr

the PPPAM

5, SCE is aut

ssion decisio

ates for Ener

ues were adj

adjustments

ransferred th

M pursuant to

thorized to tr

ons impactin

rgy (CARE)

justed to refl

s impacting t

he December

o Preliminary

ransfer amou

ng the record

) programs

flect these

the recorded

r 31, 2011

y Statement,

unts

ded

,

127

5. Operation of the CBA 1

The purpose of the CBA is to record: (1) CBA-related revenue; (2) the difference between 2

CARE discounts provided to CARE-eligible customers and CARE surcharges billed to non-exempt 3

customers; (3) the difference between the authorized CARE administration costs and actual incurred 4

CARE administration expenses; (4) costs associated with the CARE automatic enrollment program; and 5

(5) costs associated with the Energy Division’s audit of the CBA. 6

Consistent with D.06-12-038, SCE is authorized to transfer year-end balances recorded in the 7

CBA to the PPPAM. 8

Table XII-34 below summarizes the operation of the CBA during the Record Period. 9

Table XII-34 Operation of the CBA

Below SCE discusses all Commission decisions and significant adjustments impacting the 10

recorded operation of the CBA during the Record Period. 11

L ineN o . D e sc rip tio n ($ 0 0 0 )1 . B e ginning B a la nc e 5 4 ,2 9 3

2 . C o m m iss io n A utho rize d T ra nsfe rs3 . C B A A nnua l T ra nsfe r to the P P P A M (5 4 ,2 9 3 )

4 . A d jus te d B e ginning B a la nc e (L ine 1 + L ine 3 ) -

5 . S ub a c c o unts :6 . C A R E - S urc ha rge (3 1 0 ,6 4 7 ) 7 . C A R E - D isc o unt 3 3 8 ,2 6 6 8 . C A R E - A d m inis tra tive C o sts (8 ,2 9 9 ) 9 . (O ve r)/U nd e r C o lle c tio n (L ine s 6 - 8 ) 1 9 ,3 2 0

1 0 . Inte re st 2 7

1 1 . E nd ing B a la nc e (L ine 4 + L ine 9 + L ine 1 0 ) 1 9 ,3 4 6

128

a) Commission-Authorized Transfers 1

Pursuant to Preliminary Statement, Part FF, PPPAM, SCE is authorized to transfer amounts 2

recorded in the CBA to the PPPAM on an annual basis. In January 2012, SCE transferred the December 3

31, 2011 debit balance of $54.293 million recorded in the CBA to the PPPAM, as shown on Line 3 of 4

Table XII-34. 5


There were no significant adjustments or Commission decisions impacting the recorded 7

operation of the CBA during the Record Period. As described above in Section 4 of the Operation of the 8

PPPAM, the Commission adopted D.12-08-044, which among other things, established the authorized 9

revenue requirements for the CARE program for 2012 through 2014. The 2012 CARE authorized 10

revenues were adjusted to reflect this change. 11

6. NSGBA 12

a) Introduction 13

The purpose of this section is to: (1) provide the regulatory background associated with the 14

NSGBA; (2) present the entries recorded in the NSGBA during the 2012 Record Period as required by 15

Preliminary Statement, Part RR, NSGBA; (3) support the costs recorded in the NSGBA associated with 16

the New Generation Purchase Power Agreements (PPA) capacity and energy; and (4) demonstrate that 17

the entries recorded in the NSGBA are appropriate, correctly stated, and in compliance with 18

Commission decisions. 19

b) Background 20

OP 2 of D.07-09-044 authorized each IOU to establish a balancing account to record costs and 21

benefits associated with new generation resources. In compliance with D.07-09-044, SCE filed Advice 22

Letter 2284-E to establish the NSGBA.99 23

99 Advice Letter 2284-E was approved by the Commission’s Energy Division with an effective date of January 16, 2009.

129

During the Record Period, SCE recorded the costs associated with its Commission-approved 1

PPA with Long Beach Generation, LLC (LBG PPA),100 its Commission approved PPA with Blythe 2

Energy, LLC (Blythe PPA),101 and its Commission-approved Resource Adequacy Contract with Calpine 3

Energy Services, L.P.102 for the Sutter power plant. 4

In compliance with D.06-07-029, SCE conducted energy auctions for each of the foregoing 5

PPAs (the “LBG Energy Auction” and “Blythe Energy Auction”). The LBG Energy Auction concluded 6

on June 22, 2011 and resulted in a back-to-back toll with NRG Power Marketing, LLC with the term 7

August 1, 2011 to July 31, 2014. The Blythe Energy Auction concluded on June 23, 2010 and resulted 8

in SCE retaining energy and dispatch rights to the facility for the term August 1, 2010 to July 31, 2013. 9

In compliance with Resolution E-4471, SCE filed Advice Letter 2730-E where SCE entered into 10

a contract with Calpine Energy Services, LLC for Resource Adequacy from Calpine’s Sutter resource. 11

In addition, on March 26, 2009, the Commission in D.09-03-031 ordered the net capacity costs 12

and resource adequacy benefits for the four initial SCE Peakers to be allocated to all benefiting 13

customers, requiring that the Commission-authorized Peaker revenue requirement also be recorded in 14

the NSGBA. SCE’s authority to allocate these costs expires ten years from the date of commercial 15

operation for each unit, consistent with D.06-07-029, D.07-06-022, and D.08-09-012. In D.12-11-051 16

the Commission authorized a revenue requirement for the four initial Peakers to record in the 17

NSGBA.103 18

100 LBG LLC is a wholly-owned subsidiary of NRG Energy, Inc. The LBG PPA was approved by the Commission in D.07-

01-041. 101 The Blythe PPA was approved by the Commission in D.08-05-028. 102 The Calpine RA contract was entered into as a result of CPUC Resolution E-4471 and approved by the Commission per

Advice Letter 2730-E which was approved by the Commission’s Energy Division with an effective date of May 25, 2012.

103 SCE filed Advice 2826-E on December 19, 2012, implementing the 2012 GRC adopted revenue requirements and ratemaking mechanisms in accordance with D.12-11-051.

130

c) Operation of the NSGBA 1

The NSGBA records the difference between (1) recorded billed and unbilled revenue and (2) 2

recorded Commission-authorized Peaker revenue requirement, the actual benefits and costs of New 3

Generation PPAs and the initial four SCE Peakers, pursuant to D.06-07-029, D.07-09-044, D.09-03-031 4

and D.12-11-051. Table XII-35 below summarizes the operation of the NSGBA during the 2012 Record 5

Period. 6

Table XII-35 Operation of the NSGBA

d) Expenses 7

As shown on Line 2 in Table XII-35 above, SCE recorded prior period adjustments for a total 8

credit of $4.021 million related to the NSGBA.104 As discussed in Advice Letter 2826-E 105 and 9

104 The 2008-2011 Rate of Return change from 8.75% to 8.74% associated with the May 2012 adjustment and 2009-2011

Peaker CAM reclass associated with the October 2012 adjustment are provided in the NSGBA workpapers. 105 Advice Letter 2826-E implemented rates and ratemaking associated with D.12-11-051, SCE’s 2012 GRC Phase 1

decision.

L ine N o . D e sc rip tio n ($ 0 0 0 )1 . B e ginning B a la nc e 2 0 ,8 5 3

2 . P rio r Y e a r A d jus tm e nts (4 ,0 2 1 ) 3 . A d jus te d B e ginning B a la nc e (L ine 1 + L ine 2 ) 1 6 ,8 3 1

4 . R e ve nue s (1 6 4 ,9 7 8 ) 5 . E xp e nse s6 . A utho rize d P e a k e r R e ve nue R e q uire m e nt7 . N e w G e ne ra tio n P P A C o sts8 . E ne rgy A uc tio n R e la te d 9 . T o ta l E xp e nse s (L ine 6 + L ine 7 + L ine 8 )

1 0 . (O ve r)/U nd e r C o lle c tio n (L ine 4 + L ine 9 )

1 1 . Inte re s t (1 7 )

1 2 . E nd ing B a la nc e (L ine 3 + L ine 1 0 + L ine 1 1 ) (2 1 ,4 3 7 )

131

consistent with Preliminary Statement, Part RR, NSGBA, the Authorized Peaker Generation Revenue 1

Requirement (APGRR) in the NSGBA, as shown on Line 6 in Table XII-35 above, was 2

from January 1, 2012 through December 31, 2012, excluding FF&U. The New Generation PPA costs 3

totaled for the Record Period, as shown on Line 7 in Table XII-35 above. 4

Other 2012 expenses recorded during the Record Period included energy auction costs associated 5

with the Independent Evaluator responsible for monitoring and overseeing the energy auction process 6

totaled , as shown on Line 8 in Table XII-35 above. Costs recorded in the NSGBA 7

during the Record Period total , as shown on Line 9 in Table XII-35 above. 8

7. Conclusion 9

SCE requests the Commission to find that it appropriately operated the foregoing balancing 10

accounts and adjustment mechanisms during the Record Period, and that its recorded entries in these 11

accounts were appropriate, correctly stated, and in compliance with Commission decisions. 12

C. Review and Disposition of Balancing and Memorandum Accounts Pursuant to Decisions 13

06-05-016, 09-03-025, and 12-11-051 14

1. MPBA 15

a) Introduction 16


MPBA; (2) present the operation of the MPBA during the 2012 Record Period as required by 18

Preliminary Statement, Part VV, MPBA; and (3) request a Commission finding that the entries recorded 19

in the MPBA are appropriate, correctly stated, and in compliance with Commission decisions. 20

b) Background 21

In D.09-03-025, the Commission agreed with SCE’s medical program cost forecasting 22

methodology and authorized a new two-way balancing account to protect ratepayers from any 23

overestimating of expenses. In compliance with D.09-03-025, SCE filed Advice Letter 2336-E106 on 24

106 Advice Letter 2336-E was approved by the Commission’s Energy Division, effective March 30, 2009.

132

March 30, 2009 to implement the GRC-authorized revenue requirements for the 2009 Test Year, and to 1

establish the MPBA, Preliminary Statement, Part VV. In accordance with D.12-11-051, SCE filed 2

Advice Letter 2826-E on December 19, 2012 to implement the CPUC-authorized GRC revenue 3

requirements for the 2012 Test Year and 2013 Post Test Year.107 4

c) Operation of the MPBA 5

The purpose of the MPBA is to record the difference between: 1) medical, prescription drug, 6

dental, and vision (health care) plan expenses authorized by the Commission in the GRC, and 2) actual 7

health care plan expenses, after capitalization, plus 3) a debit entry of $0.1337 for each Edison 8

SmartConnect™ meter purchased per month in the distribution sub-account. As adopted in D.08-09-9

039, for each Edison SmartConnect™ meter purchased, SCE credits $1.4246 per meter of O&M 10

operational benefits per month through the deployment period to the ESCBA, beginning eight months 11

after including such meters in rate base.108 The calculations deriving the $1.4246 include $0.1337 of 12

health care-related benefits. In order to insure ratepayers only see the impact of the health care benefits 13

once, SCE debits the corresponding amount of $0.1337 per meter, per month, in the MPBA. 14

During the 2012 Record Period, SCE recorded expenses of $158.927 million in the MPBA. The 15

difference between the authorized medical programs revenue requirement and the recorded expenses 16

results in a December 31, 2012 ending balance under-collection of $7.243 million, including interest. 17

Consistent with Preliminary Statement, Part VV, any year-end over/under-collection is transferred to the 18

distribution and generation sub-accounts of the BRRBA annually, to be returned to or recovered from 19

customers. Accordingly, in January 2013, SCE transferred the 2012 under-collected ending balance of 20

$7.243 million in the MPBA to the distribution and generation subaccounts of the BRRBA to be 21

recovered from customers. The following table summarizes the recorded operation of the MPBA during 22

the Record Period. 23

107 Advice Letter 2826-E was approved by the Commission’s Energy Division, effective December 19, 2012. 108 See Edison SmartConnect™ Chapter XIII, Section A of SCE-2.

133

Table XII-36 Operation of the MPBA

Line No. ($000)

1. Beginning Balance 5,740 2. Authorized 2011 Transfer to BRRBA (January) (5,740) 3. Adjustment for Retiree/Cobra Contributions (July) (5,868) 4. Adjustment for GRC: Authorized Revenue, Juris. Rate, Capitalization Rate (Nov (8,197) 5. Adjustment for Pay As You Go True-Up (December) (3,951) 6. Adjusted Beginning Balance (Sum of Lines 1 - 5) (18,016)

7. Authorized MPBA Funding 1/ (133,505)

8. Expenses (CPUC Jurisdictional)9. Medical 208,113 10. Dental 22,514 11. Vision 3,757 12. Total (Line 9 + Line 10 + Line 11) 234,384 13. Less: Trust Reimbursement (61,479) 14. Less: Pay As You Go (13,978) 15. Total Expenses (Line 12 + Line 13 + Line 14) 158,927

16. Under Collection Before Capitalization (Line 7 + Line 15) 25,422

17. Under Collection After Capitalization (Line 16 * Capitalization Rate) 2/ 16,915 18. Extended Health Care/Medical Flex Dollars (Jurisdictionalized) (Sept.) 3/ 2,238 19. SmartConnect™ Meter Deployment Debit 4/ 6,086 20. Total (Sum of Lines 17, 18, 19) 25,239

21. Interest 20

22. Total Under Collected Balance (Sum of Lines 6, 20, 21) 7,243

1/ Jurisdictional rate applied: Jan - Oct at 95.39%; Nov - Dec at 95.7062% (per D.12-11-051).2/ Capitalization rate applied: Jan - Oct at 66.8% (1-33.2%); Nov - Dec at 62.3% (1-37.7%) (per D.12-11-051). 3/ Extended Health Care (Medical Flex Dollars) costs not capitalized. 4/ In accordance with the ratemaking adopted in D.08-09-039 pertaining to the Edison SmartConnect™ program.

Description

134

d) Description of Medical Program Expenses 1

Each year, during the Annual Enrollment period, SCE offers eligible employees and their 2

eligible dependents a variety of health care plan options from which they can choose to enroll. For 3

2012, there were a total of seven medical options and three dental options available to SCE employees. 4

These options varied depending on an employee’s geographic location. Employees could also elect to 5

waive medical coverage if they were covered by another group medical plan. Prescription drug 6

coverage provided by Express Scripts was included with every medical plan option, except Kaiser 7

Health Plan, which provides its own pharmacy coverage. In addition, all full-time and Part-Time Plus 8

employees were eligible for vision coverage through Vision Service Plan. 9

Specific information regarding the health care elections for each eligible employee, including his 10

or her enrolled dependents, is recorded in the recordkeeping system maintained by the external vendor 11

that administers the company’s benefit plans. Once benefit elections are final, the recordkeeper mails a 12

confirmation statement to each employee to review and verify that their elections and covered 13

dependents are correct. Effective with the first 2012 payroll deduction period and continuing for a total 14

of 24 deduction periods throughout the year, each employee who selected a medical or dental option 15

received a company contribution toward these plans through “Flex Dollars”, which SCE applied toward 16

the employee’s total cost of health care coverage.109 An employee’s net cost for the selected medical 17

and dental options was deducted from his or her paycheck.110 (The difference between an employee’s 18

total cost of the medical and dental options he or she elects and the Flex Dollars applicable to those 19

options represents the employee’s net contribution toward medical and dental coverage.) 20

As noted above, SCE offers one vision plan (Vision Service Plan) to eligible employees and their 21

dependents. The company pays the full cost of this coverage; therefore, no employee contributions are 22

collected. 23

109 These costs are recorded in the MPBA as Dental or Medical Flex Dollar Expenses. 110 These credits are recorded in the MPBA as Dental or Medical Flex Employee Contributions.

135

On at least a monthly basis, the external recordkeeper sends electronic eligibility files to all of 1

the health care plans specifying which employees and dependents are enrolled, including dates of hire 2

and termination, which determines coverage begin and end dates. Periodically, the company retains an 3

external firm knowledgeable in group health care insurance coverage to audit the accuracy of the 4

carriers’ eligibility records and compliance with the provisions of the health care plan. The primary 5

objectives of the audit are to: (a) measure the accuracy of health claims processing; (b) evaluate current 6

controls overseeing the claims processing and customer service operations; (c) assess performance in 7

relation to industry standards; and (d) identify areas for quality improvement, if any. 8

As employees and/or their dependents terminate their group health care coverage with SCE, the 9

individual may be offered the option of continuing their coverage for a limited period of time, as 10

required by federal law, through the Consolidated Omnibus Budget Reconciliation Act (COBRA). For 11

individuals who appropriately elect to extend their coverage, the external recordkeeper bills and collects 12

any amounts due, then remits those payments to SCE on a monthly basis.111 13

The company has made various arrangements with the health care plans regarding how they are 14

reimbursed for benefit costs. For some plans, the company contracts on an insured basis which means 15

that a fixed premium is due for each covered employee based on the family size enrolled. The 16

recordkeeper determines the premium due to the insurance carriers based on the number of covered 17

employees and their dependent coverage categories. This report is then used by the company to remit 18

monthly payments to the carriers. The company contracts with other health care plans on a self-funded 19

or flex-funded basis which means the actual costs incurred by participants and their dependents, plus an 20

administrative fee, are billed to SCE. These plans submit invoices based on the contractual agreement, 21

and include detailed lists of the participants who have received services. In both cases, payments 22

111 These payments are recorded in the MPBA as Dental, Medical, or Vision COBRA credits.

136

include the applicable health care costs of actives and those on COBRA. The Human Resources 1

Finance group processes the payments to the various plan carriers.112 2

Instead of COBRA, some employees who leave SCE at age 55 or older with at least 10 years of 3

service may be eligible to continue coverage under the company’s retiree health care program. The 4

costs of the health care coverage for retirees and their enrolled dependents (including surviving 5

dependents) are handled in a similar manner to employees and COBRA participants. The external 6

recordkeeper maintains a complete database of eligible retirees and their dependents, with effective 7

dates and elected coverage options.113 As with actives and COBRA participants, an eligible retiree may 8

change or waive health care coverage during Annual Enrollment. In addition, if a retiree moves to an 9

area with different coverage options or if the retiree becomes eligible for Medicare, he or she may also 10

change options at that time. The external recordkeeper includes the retiree information in the same 11

periodic eligibility updates to each of the health care plans as they do for employees and COBRA 12

participants. 13

A retiree’s enrollment elections dictates the amount that retiree must contribute for coverage. On 14

a monthly basis, amounts due are either deducted from a pension annuity benefit or the external 15

recordkeeper may bill the retiree directly. The trustee for the SCE Retirement Plan forwards the 16

amounts deducted from pension annuities and the external recordkeeper remits the retiree contributions 17

received through the billing process to SCE on a monthly basis.114 18

The health care plans utilize the same methods to bill SCE for retirees’ coverage costs as they do 19

for the employee and COBRA populations. However, after these health care expenses have been billed 20

and paid, an additional process takes place to identify and categorize the total retiree and dependent 21

costs. First, the recordkeeper provides data indicating what expenses were incurred for retirees and their 22

112 The payments to the health plan options are recorded in the MPBA as Dental, Medical or Vision Plan Payments or

Claims Payments. 113 This same process applies for surviving dependents of a retiree who is deceased.

114 These payments are recorded in the MPBA as Dental, Medical, or Vision Retiree Contributions.

137

dependents for fully insured plan premium payments as well as self- and flex-funded plan administrative 1

expenses billed on a per participant basis. Second, for plans that the company contracts under flex- or 2

self-funded arrangement, each health care plan provides specific data indicating what expenses were 3

incurred by enrolled retirees and their dependents, including administrative expenses not billed on a per 4

participant basis. All of the expenses for retirees, their dependents, and their surviving dependents are 5

identified and categorized by the specific trust from which SCE will be reimbursed, or alternatively, as a 6

“pay-as-you-go” expense, where no trust reimbursement will be provided. These trusts have been 7

established for SCE to fund the liabilities for PBOPs and are later used by the company to reimburse it 8

for the actual costs incurred by eligible retirees and their dependents. These trust reimbursements and 9

retiree-related expenses categorized as “pay-as-you-go,” are reversed from the MPBA.115 In other 10

words, SCE removes all health care expenses for retirees and their dependents; the only remaining costs 11

reported in the MPBA are for the health care expenses for SCE employees and their dependents. 12

Programs for Employees Not Covered by Collective Bargaining Agreements 13

Under the EIX Severance Plan for Non-represented Employees (ESP), SCE provides a variety of 14

benefits to alleviate the hardships faced by non-executive, non-represented workers who experience job 15

loss because of a Reduction in Force (RIF). These benefits are summarized below: 16

(1) Cash Severance. The ESP provides a cash severance equal to 4 weeks of base pay plus 2 weeks 17

of base pay for each year of completed service with an EIX company up to a maximum of 52 18

weeks. If the severed employee is age 40 or older, the company provides a minimum benefit of 19

4 weeks of base pay and 1 week of base pay per year of age over 40, up to a maximum of 26 20

weeks. Under the ESP, the severance benefit is paid in a lump sum. 21

(2) Retirement Enhancements. Under the ESP, a severed employee must be at least 50 years of age 22

and have 15 years of service to become eligible for retiree health care benefits. 23

115 The reversal is shown earlier on Line 14 in Table XII-36 in this section.

138

(3) Extended Health Care Coverage. Under the ESP, extended health care coverage is provided at 1

employee rates based on the employee’s years of service. The ESP provides 3 months of 2

coverage for employees with less than 5 years of service, 6 months of coverage for employees 3

with 5-9 years of service, 9 months of coverage for employees with 10-14 years of service, 12 4

months of coverage for employees with 15-19 years of service, 15 months of coverage for 5

employees with 20-24 years of service, and 18 months of coverage for employees with 25 or 6

more years of service with an EIX company. 7

(4) Education Retraining Benefits. A total of $5,000 is available for educational reimbursement for 8

employees who are severed with less than 5 years of service or $10,000 if they have 5 or more 9

years of service. Benefits must be claimed within 24 months of the termination date. 10

(5) Outplacement Assistance. Based on the classification of the severed employee, 1 to 6 months of 11

outplacement is available to assist in searching for a new position. 12

(6) Relocation Service. For employees at risk for severance who instead transfer to another position 13

within the company, a variety of support services are available, including assistance with home 14

sale, home finding, temporary living, and transportation of household goods. 15

e) Conclusion 16

SCE respectfully requests the Commission to find that the expenses recorded in the MPBA were 17

appropriate, consistent with D.09-03-025 and D.12-11-051, Advice Letters 2336-E and 2826-E 18

respectively, and are reasonable. 19

2. PCBA and PBOP BA 20

a) Introduction 21


PCBA and PBOP BA; (2) present the entries recorded in the PCBA and PBOP BA during the Record 23

Period for review; and (3) demonstrate that the entries recorded in the PCBA and PBOP BA are 24

appropriate, correctly stated, and in compliance with Commission decisions. 25

139

b) Background and Ratemaking 1

In accordance with OP 22 of D.06-05-016, SCE established the PCBA and the PBOP BA and 2

filed Advice Letter 2003-E on May 22, 2006 establishing these balancing accounts. Pursuant to this 3

decision, the over/under-collections recorded in these accounts in 2006, 2007, and 2008 were carried 4

over to the next year. Accordingly, pursuant to D.06-05-016, SCE filed Advice Letter 2331-E116 with 5

the Commission on March 17, 2009, and reported the recorded operation of the PCBA and the PBOP 6

BA for the 2006 GRC cycle beginning January 12, 2006117 and ending December 31, 2008. 7

In accordance with D.09-03-025, SCE filed Advice Letter 2336-E118 on March 30, 2009 to 8

implement the GRC-authorized revenue requirements for the 2009 Test Year and also to modify existing 9

regulatory mechanisms. Pursuant to Preliminary Statements Part OO and Part PP, SCE included the 10

2009, 2010, and 2011 operation of the PCBA and PBOP BA in its 2010, 2011 and 2012 ERRA Review 11

proceedings,119 A.10-04-002, A.11-04-001, and A.12-04-001 respectively. 12

In accordance with D.12-11-051, SCE filed Advice Letter 2826-E120 on December 19, 2012 to 13

implement the GRC-authorized revenue requirements for the 2012 Test Year and also to modify existing 14

regulatory mechanisms.121 15

In this ERRA Review proceeding, SCE is presenting the 2012 operation of the PCBA and PBOP 16

BA. 17

116 Advice Letter 2331-E was approved by the Commission’s Energy Division, effective April 16, 2009. 117 SCE’s 2006 GRC decision, D.06-05-016, was effective May 11, 2006. 118 Advice Letter 2336-E was approved by the Commission’s Energy Division, effective March 30, 2009.

119 The PCBA and PBOP BA operations for the 2009 Record Period presented in SCE’s ERRA Review Application, A.10-04-002, were approved in D.11-10-002 on October 6, 2011. The review of operations for the 2010 and 2011 Record Periods presented in SCE’s ERRA Review Applications, A.11-04-001 and A.12-04-001, are still pending before the Commission.

120 Advice Letter 2826-E was approved by the Commission’s Energy Division, effective December 19, 2012. 121 Advice Letter 2826-E modified the PCBA and PBOP BA Preliminary Statements, Part OO and Part PP, to update for the

2012 authorized amounts.

140

c) Operation of the PCBA and PBOP BA 1

The PCBA and PBOP BA record the difference between: (1) costs authorized by the 2

Commission in the GRC and (2) recorded costs, after capitalization.122 The authorized pension and 3

PBOP revenue requirements are the annual amounts authorized in D.12-11-051. The PCBA and PBOP 4

BA both include a distribution sub-account and a generation sub-account, since expenses are recovered 5

through both distribution and generation rate levels. 6

In 2012, the PCBA and PBOP BA were still impacted by the extremely poor 2008 financial 7

market returns associated with the global economic and financial crises. The U.S. stock market, as 8

measured by the Standard and Poor’s (S&P) 500 Index, returned -37% in 2008—its worst year since the 9

1930s. The markets posted positive results in 2009, 2010, 2011, and 2012, with the S&P 500 returning 10

+26.5%, +15.1%, +2.1% ,and +16.0%, respectively. Historically low interest rates, primarily related to 11

Federal Government policy around managing U.S. treasury rate levels, have substantially increased the 12

present value of the pension obligation. Thus, despite the recovery of the fund assets since the 2008 13

financial crisis lows, the liability has grown at a faster rate, hence the increase in the Internal Revenue 14

Service required contribution in 2012. The increase in funding requirements for most U.S. corporations 15

led to the passage of a funding relief measure by the U.S. Congress in 2012, which reduced 2012 16

required funding contributions for most employers. 17

See Table XII-37 below. 18

122 Capitalization is the amount removed from expense to properly reflect the total costs of construction, administration, and

general costs supporting construction activities that are not directly charged to construction work orders and included in capital.

141

Table XII-37 SCE’s Pension Assets and Obligations

($Millions)

Line No. Description 2011 2012 Change

1. Actuarial Value of Assets (January 1)

Minimum funding N/A 3,126 --

Funding Policy 3,170 3,179 9

2. Funding Liability

Minimum Funding N/A 3,000 --

Funding Policy 4,014 4,070 56

In 2011, the pension contribution was based on SCE’s Funding Policy, but in 2012 the pension 1

contribution was based on the Pension Protection Act (PPA) of 2006 Minimum Funding requirement. 2

For funding policy purposes the actuarial value of assets increased by $9 million from January 1, 2011 3

to January 1, 2012, but the value of the liabilities increased by $56 million. 4

Table XII-38 below summarizes the entries recorded in the PCBA during the Record Period. 5

1

2

3

4

5

6

7

8

9

A

jurisdicti

costs wer

minimum

amount o

on Line 4

CPUC 20

continues

123 Jurisd

the FEand as

124 CPUC

d)

Actual pensio

ionalization1

re calculated

m funding re

of $100.412

4 in Table X

012 authoriz

s to put upw

ictionalization

ERC. The methsset statistics (A

C authorized am

Summary

on costs for 2

23 and capita

d by SCE’s p

quired under

million ($16

XII-38. The a

zed amount o

ward pressure

is the separati

hodology usedA.10-11-015, S

mounts in the 2

Oper

Description

2012 were $

alization), as

pension actu

r the PPA. A

68.406 millio

actual 2012 c

of $168.406

e on pension

on of costs cov is consistent w

SCE-10, Vol. 1

2012 GRC deci

142

Table XII-ration of th

of Pension E

87.100 milli

s shown on L

ary, AonHew

Actual pensi

on before jur

contribution

million.124 T

costs. The

vered through rwith that adopt, p. 17).

ision, D.12-11-

-38 e PCBA

Expenses

ion ($146.08

Line 5 in Tab

witt Consult

ion funding c

risdictionaliz

n was 57% gr

The ongoing

resulting ov

rates authorizeted in D.04-07-

-051, issued in

80 million be

ble XII-38 a

ting (AonHe

costs were lo

zation and c

reater than 2

g impact of t

ver-collected

ed by the CPUC-022 based on u

n November 20

efore

above. The p

ewitt). This w

ower than th

capitalization

2011, but bel

the 2008 fina

d balance in t

C from those auupdated histori

012.

pension

was the

he authorized

n), as shown

low the

ancial crisis

the PCBA as

uthorized by ical cost value

d

s

s

143

of December 31, 2012 was $13.312 million, as shown on Line 6 Table XII-38 above. This amount, plus 1

associated interest, was transferred to the BRRBA to be returned to customers. 2

Table XII-39 below summarizes the entries recorded in the PBOP BA during the Record Period. 3

Table XII-39 Operation of the PBOP BA

e) Summary Description of PBOP Expenses 4

Actual PBOP costs for 2012 were $31.126 million ($51.276 million before jurisdictionalization 5

and capitalization), as shown on Line 9 in Table XII-39 above. The PBOP costs (also referred to as Net 6

Periodic Postretirement Benefit Costs or Financial Accounting Standards 106 expenses) were calculated 7

L ine N o . D e sc rip tio n ($ 0 0 0 )

1 . B e ginning B a la nc e (1 8 ,8 7 0 )

2 . 2 0 1 1 E nd ing B a la nc e T ra nsfe r to the B R R B A (Ja nua ry) 1 / 1 8 ,8 7 0

3 . A d jus te d B e ginning B a la nc e (S um o f L ine s 1 - 2 ) -

4 . A utho rize d P B O P F und ing 2 / (3 1 ,8 2 7 )

5 . P a y A s Y o u G o 1 2 ,6 7 9 6 . P B O P F und ing 1 8 ,7 6 7 7 . M e d ic a re P a rt D R e im b urse m e nt (2 ,3 6 3 ) 8 . S e ve ra nc e 2 ,0 4 3

9 . T o ta l P B O P E xp e nse s 2 / (S um o f L ine s 5 - 8 ) 3 1 ,1 2 6

1 0 . (O ve r)/U nd e r C o lle c tio n (L ine 4 + L ine 9 ) (7 0 1 )

1 1 . Inte re s t (0 ) 1 2 . E nd ing B a la nc e (L ine 3 + L ine 1 0 + L ine 1 1 ) (7 0 2 )

1 / P ur sua n t t o P r e lim in a r y St a t e m e n t P a r t P P , P o st E m p lo y m e n t B e n e f it s O t h e r T h a n P e n sio n s ( P B O P ) C o st s B a la n c in g A c c o un tT h e 2 0 1 1 o p e r a t io n s o f t h e P B O P B A h a v e be e n r e v ie we d by t h e C o m m issio n in A .1 2 - 0 4 - 0 0 1 , SC E 's 2 0 1 2 E R R AR e v ie w A p p lic a t io n . T h e C o m m issio n h a s n o t issue d a de c isio n in t h is A p p lic a t io n .

2 / C P U C jur isdic t io n a liz a t io n a n d c a p it a liz a t io n r a t e s a p p lie d a t 9 5 .7 1 % a n d 3 7 .7 % , r e sp e c t iv e ly , a s a do p t e din D .1 2 - 1 1 - 0 5 1 . Se v e r a n c e e x p e n se s a r e n o t c a p it a liz e d.

144

by SCE’s PBOP actuary, AonHewitt. Tax-deductible amounts for the Pay As You Go group (pre-1993 1

Management and Administrative group retiree costs), SCE’s tax-deductible PBOP trust funding, and a 2

credit for Medicare Part D reimbursements equal the FAS 106 expense amount calculated by 3

AonHewitt. Actual PBOP costs were lower than the 2012 authorized amount of $31.827 million 4

($53.378 million before jurisdictionalization and capitalization), as shown on Line 4 in Table XII-39 5

above. Favorable PBOP claims experience, a plan amendment adopted in 2009 and positive market 6

performance have helped to restrain PBOP costs. The actual 2012 contribution was 51% greater than 7

2011 but below the CPUC 2012 authorized amount of $53.378 million. The resulting over-collected 8

balance in the PBOP BA as of December 31, 2012 was $0.701 million, as shown on Line 10 in Table 9

XII-39 above. This amount, plus associated interest, was transferred to the BRRBA to be returned to 10

customers. 11

f) Conclusion 12

SCE respectfully requests the Commission to find that the costs recorded in the PCBA and 13

PBOP BA were properly recorded and consistent with D.12-11-051 and Advice Letter 2826-E. 14

3. RSMA 15

a) Introduction 16


RSMA; (2) present the entries recorded in the RSMA during the 2012 Record Period for Commission 18

review; and (3) demonstrate that the entries recorded in the RSMA are appropriate, correctly stated, and 19

in compliance with prior Commission decisions. 20

b) Background 21

Pursuant to OP 21 of D.06-05-016, SCE submitted Advice Letter 2003-E to establish the RSMA 22

to track the difference between authorized in the GRC and the actual amount of results sharing paid to 23

employees.125 The Results Sharing Program is SCE’s short-term annual incentive compensation 24

125 Advice Letter 2003-E was approved by the Commission’s Energy Division with an effective date of May 22, 2006.

145

program under which eligible employees, including represented employees, can earn pay based on their 1

job performance and SCE’s performance on pre-established goals. It is an important component of 2

SCE’s overall compensation package that, combined with other forms of compensation, provides 3

compensation amounts that are at market rates. Each year the results sharing award increases or 4

decreases based on overall SCE business results. If actual results sharing payouts are less than the 5

amount authorized for the year, the over-collected amount is refunded to customers. Since the RSMA is 6

a one-way account, SCE is not authorized to recover under-collections. 7

In D.12-11-051, the Commission approved the continued use of the RSMA to track the 8

difference between the results sharing amounts included in the GRC-authorized revenue requirements 9

for the 2012 Test Year and actual amounts paid to employees. SCE submitted Advice Letter 2826-E126 10

on December 19, 2012, updating Preliminary Statement, Part N.8, RSMA. 11

c) Operation of the RSMA 12

Table XII-40 summarizes the entries recorded in the RSMA during the Record Period. 13

126 Advice Letter 2826-E was approved by the Commission’s Energy Division with an effective date of December 19, 2012.

1

2

3

4

5

6

7

8

9

10

11

12

13

T

less than

Part N.8,

S

properly

D. R

1

T

Cell Prog

Record P

appropria

127 Table

d)

The ending b

a thousand

, this amount

CE respectfu

recorded an

Review and D

. FCPM

a)

The purpose o

gram Memor

Period, and (

ate, correctly

XII-40 Line 6

Conclusion

alance rema

dollors, as sh

t was transfe

fully requests

nd consistent

Disposition

MA

Introductio

of this sectio

randum Acc

3) request a

y stated, and

Ending Balanc

TabOperatio

n

aining in the

hown on Lin

erred to the B

s the Commi

t with D.12-1

of Other M

on

on is to: (1) p

count (FCPM

Commission

d in complian

ce is zero due t

146

ble XII-40on of the RS

RSMA as of

ne 6127 in Ta

BRRBA in J

ission to find

11-051 and A

Miscellaneou

provide the r

MA), (2) pres

n finding tha

nce with Com

to rounding.

SMA

f December

able XII-40.

January 2013

d that the co

Advice Lette

us Account B

regulatory b

sent the oper

at the entries

mmission de

31, 2012, w

Pursuant to

3 to be return

osts recorded

er 2826-E.

Balances

ackground a

ration of the

s recorded in

ecisions.

was an over-c

o Preliminary

ned to custo

d in the RSM

associated w

FCPMA du

n the FCPMA

collected by

y Statement,

omers.

MA were

with the Fuel

uring the

A are

147

b) Background and Ratemaking 1

In D.10-04-028, the Commission authorized SCE to establish the Fuel Cell Program 2

Memorandum Account to record incremental costs associated with SCE’s implementation of its Fuel 3

Cell Program to install three utility-owned fuel cells on the University of California Santa Barbara (UC 4

Santa Barbara), California State University San Bernardino (CSU San Bernardino), and California State 5

University Long Beach (CSU Long Beach) campuses. In accordance with OP 4 of D.10-04-028, the 6

Commission directed SCE to record actual capital costs and O&M costs in the FCPMA and transfer the 7

FCPMA balance each month to the generation sub-account of the BRRBA, as long as the amounts are 8

no higher than the estimates approved in the decision.128 Review of the FCPMA occurs in SCE’s annual 9

April ERRA proceedings. 10

In SCE’s 2012 General Rate Case Application, A.10-11-015, SCE forecast a revenue 11

requirement for the Fuel Cells Program to include capital-related expenditures and O&M expenses and 12

requested that the FCPMA be eliminated. SCE revised its forecast in the Update Testimony129 since it 13

would not be going forward with the fuel cell installation at CSU Long Beach. In the 2012 GRC 14

Decision, D.12-11-051, the Commission approved the continued use of the FCPMA, pursuant to OP 35, 15

and a forecast revenue requirement for FCPMA. SCE submitted Advice Letter 2826-E130 on December 16

19, 2012, updating Preliminary Statement, Part N.43, FCPMA. 17

c) Operation of the FCPMA 18

The following Table XII-41 shows expenses of $0.006 million recorded in the FCPMA during 19

the 2012 Record Period. 20

128 The FCPMA records the difference between the recorded revenue requirement up to $19.1 million in capital-related

expenditures and up to $8.9 million in O&M expenses associated with SCE’s fuel cell program and the FCP revenue requirement forecast authorized in D.12-11-051.

129 SCE 2012 GRC A.10-11-015 Update Testimony, SCE-84, was filed on October 24, 2011. 130 Advice Letter 2826-E was approved by the Commission’s Energy Division with an effective date of December 19, 2012.

148

Table XII-41 Operation of the FCPMA

d) FCPMA Recorded Expenses - Details 1

The $0.006 million of expenses consist of O&M expenses for the fuel cell installed at UC Santa 2

Barbara. Some of the O&M activities include completion of regular site inspections, as well as 3

managing Environmental Health and Safety documents. 4

Cost recovery of capital expenses will be requested once all of the fuel cells have been installed, 5

commissioned, and turned over to SCE’s Power Production group for operation and long-term 6

maintenance. 7

e) Conclusion 8

In conclusion, SCE requests the Commission to find that: (1) the amounts recorded in the 9

FCPMA for the Record Period are reasonable and consistent with Commission decisions, D.10-04-028 10

and D.12-11-051. 11


1 . B e ginning B a la nc e -

2 . A utho rize d R e ve nue R e q uire m e nt 1 / (1 ,1 4 5 )

3 . O p e ra ting E xp e nse s 6

4 . (O ve r)/U nd e r C o lle c tio n (L ine 2 + L ine 3 ) (1 ,1 3 9 )

5 . T ra nsfe r to B R R B A (D .1 0 - 0 4 - 0 2 8 ) 1 ,1 3 9

6 . E nd ing B a la nc e -

1 / 2012 a u t h o rize d a s a d o p t e d in D .12-11-051.

149

E. Review of Miscellaneous Account Balances for Recovery 1

1. PDDMA 2

a) Introduction 3


PDDMA, (2) present the operation of the PDDMA during the Record Period, and (3) request a 5

Commission finding that the entries recorded in the PDDMA are appropriate, correctly stated, and in 6

compliance with Commission decisions. 7

b) Background 8

In D.06-05-016,131 the Commission excluded SCE’s forecast of Project Development Division 9

(PDD) costs from the authorized revenue requirement in the 2006 GRC. The Commission drew a 10

distinction between PDDMA-eligible “supportive” costs, which may or may not result in a proposed 11

new project, and non-PDDMA-eligible costs that are in fact associated with a proposed new project. In 12

accordance with the decision, SCE submitted Advice Letter 2003-E establishing the PDDMA to track 13

the PDD’s recorded support costs132 in an interest bearing account. These expenses include, but are not 14

limited to, the following: 15

� Identifying locations for new generation. 16

� Evaluating generation technologies. 17

� Monitoring and participating in regulatory and legislative generation-related 18

initiatives. 19

� Developing the best option outside negotiation for future generation. 20

The Commission made clear in D.06-05-016 that SCE is entitled to recover its costs recorded in 21

the PDDMA, provided they are related to the type of support functions identified in that decision and do 22

not exceed SCE’s forecasted amount. This is irrespective of whether the support functions actually lead 23

131 D.06-05-016, 2006 GRC, pp. 52-53. 132 Advice Letter 2003-E was approved by the Commission’s Energy Division with an effective date of May 22, 2006.

150

SCE to pursue a specific project; and if SCE elects to pursue a specific project, irrespective of whether 1

the Commission approves SCE’s related application.133 2

In D.09-03-025,134 the Commission reaffirmed that the type of support expenses listed above 3

should be recorded in the PDDMA, and should not exceed the forecast for the PDDMA. 4

In D.12-11-051,135 the Commission adopted SCE’s forecast of $5.80 million for Test Year 2012, 5

and requested that SCE continue tracking authorized support functions (listed above) in the PDDMA. 6

c) Operation of the PDDMA 7

The purpose of the PDDMA is to track the difference between the PDD recorded costs and the 8

PDD forecast as authorized in D.12-11-051. As shown on Line 3 of Table XII-42 below, PDDMA 9

recorded expenses were $2.924 million during the Record Period, with an over-collected ending balance 10

of $3.363 million to be returned to customers, as shown on Line 6 of Table XII-42. 11

133 D.06-05-016, pp. 52-53. 134 D.09-03-025, p. 42. 135 D.12-11-051, pp. 78-79, 825. COL 46-47.

151

Table XII-42 Operation of the PDDMA

d) Preliminary Statement Modification 1

The PDDMA preliminary statement directs the amounts recorded in the PDDMA to be reviewed 2

for reasonableness in the annual April ERRA proceedings. Those costs found reasonable are then 3

transferred to the generation sub-account of the BRRBA. Since the Commission adopted a forecast 4

revenue requirement in D.12-11-051, SCE requests that the PDDMA preliminary statement be modified 5

to include the following language: “SCE shall transfer on an annual basis any over- or under-collection 6

recorded in the PDDMA as of December 31 to the generation sub-account of the BRRBA to be returned 7

to or recovered from customers. The operation of the PDDMA shall be reviewed annually in the April 8

ERRA review proceeding.” This change will be consistent with other accounts that transfer over- or 9

under-collections annually to the BRRBA and are reviewed in the annual April ERRA proceedings. 10

e) PDD Recorded Expenses – Details 11

Table XII-43 lists the expense categories appropriately recorded to the PDDMA. These 12

categories are described below. Other details are provided in workpapers. 13

L ine N o . D e sc rip tio n ($ 0 0 0 )1 . B e ginning B a la nc e 1/ -

2 . A utho rize d R e ve nue R e q uire m e nt 2 / (6 ,2 8 4 )

3 . R e c o rd e d P ro je c t D e ve lo p m e nt D ivis io n E xp e nse s 2 ,9 2 4

4 . (O ve r)/U nd e r C o lle c tio n (L ine 2 + L ine 3 ) (3 ,3 6 0 )

5 . Inte re s t (3 )

6 . E nd ing B a la nc e (L ine 4 + L ine 5 ) (3 ,3 6 3 )

1 / F o r p u rp o s e s o f t h is t e s t im o n y , t h e b e g in n in g b a la n c e h a s b e e n a d ju s t e d t o re m o v e $4 .121 & $3.124 m illio n c u rre n t ly u n d e r C o m m is s io n re v ie w in ER R A A .11-04-001 & A .12-04-001, re s p e c t iv e ly .2 / 2012 A u t h o rize d a s a d o p t e d in D .12-11-051.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

O

evaluatin

staff, as w

SCE’s pr

and deter

functions

S

expenses

technolog

rentals, m

organizat

internal s

A

totaled $

project m

Outside Servi

ng generation

well as misc

rocurement d

rmination, co

s.

CE recorded

s to educate i

gies. It inclu

mileage, mea

tions that ed

services fees

Authorized st

1.107 millio

managers, an

(1) Ou

ices consist o

n technologi

ellaneous an

department i

ontract dispu

(2) Mi

d $0.099 mil

its employee

udes confere

als, parking,

ducate staff, a

s are also inc

(3) Lab

taffing expen

on. SCE’s st

d one projec

TabP

2012 Expe

utside Servic

of $0.940 m

ies and site s

nd procurem

include mate

ute resolutio

iscellaneous

llion of costs

es on renewa

ence fees and

and hotels.

as well as m

cluded in this

bor

nses associat

taff included

ct manager w

152

ble XII-43PDDMA enses by Ca

ces

million of exp

selection. It

ment services

erial and serv

n, purchase

Expenses

s in miscella

able and alte

d related em

Expenses fo

miscellaneous

s category.

ted with proj

d one manage

with PDD-re

ategory

penses for se

also include

. Generally,

vice acquisit

order proces

aneous expen

ernative gene

mployee trave

or publicatio

s office supp

oject develop

er, one admi

lated activiti

everal consul

es expenses f

, procuremen

tion, contrac

ssing as wel

nses. These

eration and o

el expenses s

ons and mem

plies, some c

pment divisio

inistrative as

ies.

lting compan

for temporar

nt services p

ct terms risk

l as other ba

costs includ

other generat

such as air fa

mberships to

contract labo

on-related ac

ssistant, five

nies

ry contract

provided by

assessment

ack office

de SCE’s

tion

are, car

or, and

ctivities

e senior

153

(4) Generation Planning & Strategy Support (GP&S) 1

SCE recorded $0.178 million in this PDD category, primarily for GP&S labor assistance to PDD 2

staff on the generation technologies and site selection studies. 3

(5) Labor and Expense Chargebacks 4

SCE recorded $0.046 million in chargebacks from other departments. This category tracks labor 5

and expense charges to PDD from other internal SCE departments for assistance to PDD staff on the 6

generation technologies and site selection studies. 7

(6) Membership/Dues 8

SCE recorded $0.554 million to participate in certain Electric Power Research Institute (EPRI) 9

programs during 2012, including: separate photovoltaic (PV) and concentrated PV collaboratives; an 10

advanced water-conserving cooling technologies development and demonstration program; a program 11

looking at the challenge in integrating distributed renewables; a program investigating the effectiveness 12

of existing and new equipment used to mitigate fish entrainment and impingement in once-through-13

cooled plants; and a report jointly written by EPRI and SCE identifying best practices of SCE’s Solar 14

PV Program.136 15

(7) Conclusion 16

SCE requests the Commission to find that the costs recorded in the PDDMA during the Record 17

Period were related to the type of support functions identified in D.06-05-016 and are, therefore, 18

recoverable. Upon a Commission finding that these costs are recoverable, SCE will transfer the ending 19

balance, with accrued interest through the date of transfer, to the generation sub-account of the BRRBA. 20

136 This report entitled: “Southern California Edison’s Solar Rooftop Program” is available to the public, and can be

downloaded from the following EPRI website link: http://my.epri.com/portal/server.pt?Product_id=000000000001026662

154

2. PAACBA 1

a) Introduction 2

The purpose of this chapter is to: (1) provide the regulatory background of the PAACBA; (2) 3

present the entries recorded in the PAACBA from 2008 through 2012 for Commission review; (3) 4

demonstrate that the costs recorded in the PAACBA are appropriate, correctly stated, and in compliance 5

with prior Commission decisions; and (4) propose the disposition of the recorded over-collection of 6

$2.196 million to be returned to customers. 7

b) Background 8

The PAACBA was established to track and record expenses related to the administrative costs of 9

SCE’s contracts for its Aggregator Managed Portfolio (AMP) Program.137 On October 17, 2007, SCE 10

filed A.07-10-013 seeking approval of eight contracts with third-party aggregators to provide SCE with 11

firm, reliable, demand response resources for up to five years beginning in 2008. On March 13, 2008, 12

the Commission issued D.08-03-017 which approved four of the eight AMP contracts including all 13

associated capacity and administrative costs. On May 22, 2008, SCE filed AL 2243-E to establish 14

Preliminary Statement “Part L, Purchase Agreement Administrative Costs Balancing Account 15

(PAACBA)” to track and record SCE’s administrative costs related to the AMP contracts in accordance 16

with D.08-03-017.138 17

On June 2, 2008, SCE filed its Demand Response application A.08-06-001 seeking Commission 18

approval of its 2009-2011 demand response programs, goals, and budgets that included four additional 19

AMP contracts for up to four years beginning in 2009. In D.09-08-027, the Commission approved a 20

settlement agreement approving capacity and administrative costs for only two additional AMP 21

contracts.139 22

137 On March 15, 2013, SCE filed AL 2862-E to modify Preliminary Statement Part L, PAACBA, in accordance with D.13-

01-024 and to change reference of demand response contracts (DRC) to Aggregator Managed Portfolio (AMP). 138 The Commission approved SCE’s AL 2243-E on June 16, 2008. 139 SCE’s AL 2404-E is deemed effective as of December 18, 2009.

1

2

3

4

5

6

7

8

9

10

11

12

A

were reco

08-027, a

As of De

Annu

T

incurred

Commiss

annually

$0.014 m

return to

date thro

AMP contrac

orded to the

authorized a

ecember 31,

ualized AM

c)

The purpose o

by SCE for

sion in D.08

to the BRRB

million of int

customers.

ugh the Rec

ct capacity an

BRRBA and

total of $4.9

2012, SCE s

MP ContracFo

Operation

of the PAAC

its AMP con

-03-017 and

BA to be ret

erest was rec

Table XII-4

ord Period.

nd administr

d PAACBA

924 million f

spent a total

Tact Administrr the Perio

of the PAAC

CBA is to rec

ntracts, and t

d D.09-08-02

turned to or r

corded in the

45 below sum

155

rative costs,

, respectivel

for administ

of $2.728 m

able XII-44rative Authd 2008 thro($000)

CBA

cord the diff

the authorize

27. Annual i

recovered fr

e PAACBA

mmarizes the

approved in

ly. The Com

trative costs

million as sho

horized Funough 2012

ference betw

ed revenue r

interest expe

rom custome

and transfer

e operation o

n D.08-03-01

mmission, in

for the perio

own in Table

nding and A

ween the adm

requirement

ense is calcu

ers. During t

rred to the B

of the PAAC

17 and D.09-

D.08-03-01

od 2008 thro

e XII-44 bel

Actual Cost

ministrative c

approved by

ulated and tra

the period 20

BRRBA annu

CBA from its

-08-027,

7 and D.09-

ough 2012.

low.

ts

costs,

y the

ansferred

008-2012,

ually to

s effective

1

2

3

4

5

6

7

8

9

10

A

during th

direct lab

activities

operation

Non-labo

support c

Below ar

2008 thro

Purc

d)

As shown in T

he five years

bor and non-

s. Direct lab

ns managem

or expenses t

costs for cust

re the annual

ough 2012.

chase AgreeSumma

Recorded

Table XII-44

, as authoriz

-labor expen

or consisted

ent and anal

to support th

tomer servic

lized expens

Taement Adminary For the

Expenses fo

4, administra

zed in D.08-0

ses to manag

d of full-time

lytical suppo

he AMP con

ce support, p

ses for the la

156

able XII-45nistrative CoPeriod 2008($000)

or Programs A

ative costs fo

03-017 and D

ge the AMP

e staffing for

ort, as well a

tracts and pr

procurement,

abor and non

Costs Balanci8 through 20

Authorized

for SCE’s AM

D.09-08-027

contracts, th

r program m

as oversight b

rogram inclu

, and inform

n-labor activi

ing Account012

in 2008-201

MP contract

7. Administr

he AMP Pro

management a

by senior ma

uded general

mation and no

ities recorde

t

12

s totaled $2.

rative costs i

ogram, and re

activities suc

anagement p

l and admini

otification sy

ed to PAACB

.728 million

included

elated

ch as

personnel.

istrative

ystems.

BA from

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

F

costs to t

the previ

returned

as of Dec

subaccou

collection

subaccou

F. E

1

T

demonstr

more det

Decembe

2

T

provided

140 The L

Annu

e)

or the period

the PAACBA

ous year in t

to customer

cember 31, 2

unt of the BR

n will be retu

unt of the BR

ESMA and L

. Introd

This testimon

rates that the

ail below, S

er 31, 2012 i

. ESMA

a)

The need for

d substantial

CTA is a sub-a

ualized PAAFo

Dispositio

d 2008 throu

A, plus $0.0

the PAACBA

s. SCE prop

2012, plus ac

RRBA. Upo

urned to cus

RRBA in dis

LCTA

duction

ny provides a

e litigation c

CE is reques

in the amoun

A and LCTA

Backgroun

the ESMA a

historical an

account of the

TaACBA Actur the Perio

on of the Dec

ugh 2012, SC

14 million in

A was transf

poses to tran

ccrued intere

on Commissi

stomers when

stribution rat

an overview

osts recorde

sting to reco

nt of $3.474

A Overview

nd and Settle

and LCTA a

nd backgroun

ESMA.

157

able XII-46ual Costs byd 2008 thro($000)

cember 31, 2

CE recorded

n associated

ferred to the

nsfer the rem

est through t

ion approval

n SCE conso

te levels follo

of the ESM

d in the LCT

over 90% of t

million, plu

w

ement Resul

arose from th

nd informati

y Labor andough 2012

2012 Balance

d $2.728 mill

interest. Ea

distribution

maining over-

the date of tr

l, the Decem

olidates the b

owing a dec

MA and LCTA

TA are reaso

the amount r

us accrued in

lts

he California

ion regarding

d Non-Labo

e in the PAA

lion in actua

ach January,

n sub-accoun

-collected ba

ransfer, to th

mber 31, 2012

balance reco

cision in this

A140 during

onable. In ad

recorded in t

nterest.

a Energy Cri

g the origin

or

ACBA

al AMP admi

the interest

nt of the BRR

alance in the

he distributio

2 PAACBA

orded in the

Application

the Record P

ddition, as d

the LCTA a

isis of 2000-

of the crisis

inistrative

recorded in

RBA to be

e PAACBA

on

over-

distribution

n.

Period and

discussed in

s of

2001. SCE

and the

158

events that gave rise to the ESMA and LCTA in its prepared testimony in A.05-04-004.141 That 1

discussion includes a description of SCE’s efforts to secure refunds from suppliers who had overcharged 2

SCE and other California utilities for power purchases in the wholesale markets regulated by the FERC. 3

These refunds have been mostly obtained through extensive settlement discussions to resolve refund 4

claims filed by SCE and other California parties at FERC against certain suppliers, as well as through 5

civil lawsuits against other suppliers. All refunds received to date by SCE under the settlement 6

agreements have been recorded in the ESMA. 7

b) October 2001 Settlement Agreement and Advice Letter 1811-E 8

On October 2, 2001, SCE and the Commission entered into a settlement agreement (Settlement 9

Agreement) resolving the SCE/Commission filed rate doctrine case. Article 3 of the Settlement 10

Agreement provides for certain offsets to energy supplier refunds, resulting in net refunds returned to 11

SCE’s customers. FERC settlements were pursued over the next several years following the Settlement 12

Agreement, as described in SCE’s testimony in Exhibit SCE-2 in A.05-04-004. 13

On July 23, 2004, SCE filed Advice Letter 1811-E requesting authority to establish the ESMA to 14

record: 15 � Refunds received from energy settlement agreements 16

� Actual litigation costs and professional fees 17

� Amounts SCE pays to other market participants 18

� 10% of net refunds for SCE’s shareholders 19

c) Resolution E-3894 and Subsequent Commission Approvals 20

On November 19, 2004, the Commission issued Resolution E-3894 (Resolution) in response to 21

SCE’s Advice Letter 1811-E. In the Resolution, the Commission: 22 � Adopted SCE’s proposal to establish the ESMA to record energy supplier refunds 23

� Authorized SCE to recover its actual litigation costs and professional fees associated with the 24

energy supplier settlement agreements 25

141 SCE’s April 2005 ERRA Review proceeding, Exhibit SCE-2, pp. 68-71.

159

� Authorized SCE to recover amounts paid to other market participants 1

� Authorized SCE to retain 10% of net refunds for the benefit of its shareholders 2

In compliance with the Resolution, SCE filed Advice Letter 1811-E-A on November 29, 2004 3

establishing the ESMA and LCTA.142 The Commission has since approved the operation of the ESMA 4

and LCTA for the 2004, 2005, 2006, 2007, 2008, and 2009 ERRA Record Periods in D.06-01-007, 5

D.06-11-016, D.07-12-027, D.08-11-021, D.10-07-049, and D.11-10-002 respectively.143 144 6

d) SCE’s Offer to Forego the Shareholder Incentive 7

As described in detail in SCE’s April 2, 2012 ERRA Application, SCE has offered to forego the 8

10% shareholder incentive for refunds received from FERC non-jurisdictional (i.e., municipal) suppliers 9

and the 10% shareholder incentive for refunds from all suppliers related to what is known as the 10

“Summer Period” of the Energy Crisis for “new” settlements. That offer was prompted by a request 11

from CPUC General Counsel Frank Lindh, and was predicated on SCE recovering 100% of the litigation 12

costs; i.e., ratepayers will fund 100% of the litigation costs as recorded in this account. Previously, 13

ratepayers were effectively paying 90% of the litigation costs. As discussed in more detail below, the 14

2012 and forward ongoing litigation costs will predominately be related to efforts in achieving refunds 15

from municipal supplier and from all suppliers for the Summer Period (because the Refund Period 16

refunds have largely already been “won” at FERC). Because SCE’s shareholders will no longer retain 17

10% of these refund recoveries, SCE’s shareholders should not have to pay 10% of the litigation costs 18

incurred to obtain them. In other words, SCE’s ratepayers will retain 100% of these future recoveries, 19

therefore SCE’s ratepayers should pay 100% of the litigation costs incurred to obtain them. For 2012, 20

SCE is willing to continue to effectively fund 10% of the litigation costs. If and when SCE’s proposal 21

142 Advice Letter 1811-E-A was approved by the Commission’s Energy Division with an effective date of November 29,

2004. 143 The Commission has not yet issued a final decision in SCE’s April 1, 2011 ERRA Application, A.11-04-001, for the

2010 Record Period Review. 144 The Commission has not yet issued a final decision in SCE’s April 2, 2012 ERRA Application, A.12-04-001, for the

2011 Record Period Review.

1

2

3

4

5

6

7

8

9

from last

settlemen

decision

litigation

3

T

S

in Januar

million a

t year’s ERR

nt of A.12-04

in that dock

n costs.

. Opera

The Table XI

CE transferr

ry 2012. Du

as summarize

RA filing is a

4-001 that in

ket), SCE wil

ation of the

II-47 below s

red the Dece

uring the Rec

ed below:

accepted by t

ncorporates t

ll amend its

ESMA

summarizes

TabOperatio

ember 31, 20

cord Period,

160

the Commis

this proposa

tariffs to ens

the ESMA a

ble XII-47on of the ES

011 ESMA c

SCE receive

ssion (SCE a

al, but the Co

sure that rate

activity duri

SMA

credit balanc

ed energy su

and DRA file

ommission h

epayers pay

ing the Reco

ce of $47.736

upplier refun

ed an uncont

has not yet is

100% of the

ord Period.

6 million to

nds totaling $

tested

ssued a final

e incurred

the ERRA

$9.810

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

In

approved

settlemen

(EMMT)

FERC, an

During th

first was

against A

received

$72,726 w

SCE’s re

between

that a por

payment

It

which rep

SCE con

n 2011, the C

d by FERC a

nts at FERC

) and Califor

nd refunds w

he Record Pe

a NEGT ban

American Ho

from settlem

was made to

efund settlem

SCE and MW

rtion of SCE

is shown on

t is importan

presents app

tinued, and w

California Pa

and funds we

in 2012 whi

rnia Polar Po

were distribu

eriod, SCE r

nkruptcy dis

ome Assuran

ments during

o the Metrop

ment proceed

WD to share

E’s purchase

n Line 5 of T

nt to note tha

proximately 7

will continu

arties reache

ere distribute

ich had been

ower Broker

uted, in 2012

received two

stribution. T

nce Company

g the Record

politan Water

ds from 2011

e a fixed per

s in the Pow

Table XII-47

at the shareho

7.5% of the

e, to receive

161

Table XII-

ed a settleme

ed during the

n reached wi

rs (Cal Polar)

2; and the Ca

o distribution

The other wa

y (AHAC) o

Period are s

r District (M

1-2012. This

centage of s

wer Exchange

.

older recove

$9.810 milli

e shareholder

-48

ent agreemen

e Record Per

ith Edison M

r). The EMM

al Polar Settl

ns related to

as a distribut

on an NEGT

shown above

MWD), reflec

s payment is

ettlement pr

e were made

ery for the 20

ion in total r

r recoveries

nt with NV E

riod. The C

Mission Mark

MT settlemen

lement was a

the 2008 NE

tion of a Pow

T surety bond

e in Table X

cting their ag

s consistent w

roceeds in co

e on behalf o

012 Record

refunds recei

(albeit at a r

Energy, whic

California Par

keting and T

nt was appro

approved in

EGT settlem

wer Exchang

d. The amou

XII-48. A pay

greed-upon s

with the 200

onsideration

of MWD. Th

Period is $0

ived. The re

reduced leve

ch was

rties filed

Trading

oved by

2013.

ment. The

ge claim

unts SCE

yment of

share of

08 agreemen

of the fact

he MWD

.744 million

eason that

el compared

t

n,

162

to the previous 10% authorization amount) from non-municipal suppliers, is that the settlements the 1

California Parties reach with suppliers are global in nature. Therefore, these global settlements include a 2

Refund Period component, in addition to the Summer Period component on which SCE has agreed to 3

forego the shareholder incentive. In addition, the National Energy & Gas Transmission, Inc. (NEGT) 4

settlement refunds received during the Record Period are not related to “new” settlements, but rather 5

relate to the 2008 NEGT settlement which was subject to SCE’s 10% shareholder incentive. 6

4. ESMA Transfer to the ERRA 7

In accordance with several Commission decisions,145 SCE files its annual ERRA forecast 8

application each August requesting adoption of the ERRA forecast period revenue requirements. 9

a) 2013 ERRA Forecast Application 10

On August 1, 2012, SCE filed its 2013 ERRA Forecast Application, A.12-08-001. On 11

November 16, 2012 SCE supplemented its August 2012 testimony, including applicable balancing 12

account balances, using recorded data through October 2012, and forecasted balances for November and 13

December 2012. 14

As of this filing, a final Commission decision has not been rendered in A.12-08-001. Pursuant to 15

a Commission decision, SCE will file an advice letter and implement the ERRA proceeding revenue 16

requirement and rate level change and include the December 31, 2012 over-collected ESMA balance of 17

$9.006 million. SCE transferred the December 31, 2012 ESMA over-collected balance to the ERRA in 18

January 2013. 19

5. Operation of the LCTA 20

The Table XII-49 below summarizes the LCTA Record Period activity to arrive at the December 21

31, 2012 under-collected balance of $3.474 million. The reasonableness of litigation costs recorded in 22

the LCTA during the Record Period is discussed below. 23

145 D.04-01-048, D.04-01-050, and D.04-03-023.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

6

T

refunds a

customer

ESMA, i

towards o

from the

the ESM

allocated

Commiss

B

resulted t

extensive

completin

. Reaso

The October

against seller

rs net of litig

n cases whe

outside attor

allocated sh

A/LCTA, sh

d to SCE for

sion for reco

Because of th

to address th

e use of outs

ng discovery

onableness o

2001 SCE/C

rs of power d

gation fees an

re the Califo

rney and con

hare of the se

hould SCE’s

litigation co

overy of the d

he substantia

he events in t

side attorney

y in the FER

TabOperatio

of Litigation

Commission

during the en

nd costs. As

ornia Parties

nsultant costs

ettling suppli

s actual litiga

ost recovery

difference.

al and specia

the Californi

ys and expert

RC proceedin

163

ble XII-49on of the L

n Costs

settlement a

nergy crisis,

s authorized

have agreed

s, SCE’s sha

ier’s refunds

ation expens

by the Califo

alized FERC

ia energy cri

ts. The extre

ngs and the l

CTA

agreement es

, and that ref

d by the Com

d upon a spe

are of such a

s. Under the

ses exceed th

fornia Parties

and federal

isis, SCE ha

eme time lim

large volume

stablished th

funds would

mmission’s d

ecific allocat

allocation ma

e Commissio

he totals that

s, SCE may

appellate co

as necessarily

mitation imp

e and compl

hat SCE wou

be returned

decision estab

tion of settle

ay be recove

on’s decision

t have been e

file separate

ourt litigation

y been requi

osed by the

exity of the

uld pursue

d to

blishing the

ment funds

ered directly

ns approving

expressly

ely with the

n that has

ired to make

deadline for

g

r

164

investigation and related analysis further contributed to SCE’s need for outside assistance. SCE and its 1

outside attorneys and consultants have participated closely and directly with Commission personnel 2

(including General Counsel Frank Lindh), the other two major California electric utilities ( PG&E and 3

SDG&E), the Attorney General’s office, and the California Department of Water Resources (acting 4

through its California Energy Resource Scheduling division) in the subsequent investigations and 5

litigations. The cooperative efforts of this group, which is generally known as the “California Parties,” 6

have facilitated some sharing of the workload but have also required a considerable investment of time 7

and resources to achieve the consensus necessary for the California Parties to speak with one voice. 8

The group effort has been successfully employed to respond to the inadequate settlements FERC 9

unilaterally struck with various parties accused of Enron-style market manipulation. The California 10

Parties jointly made successful motions at the Ninth Circuit to prevent FERC from ignoring the evidence 11

of market manipulation. More than one hundred fifty appeals of FERC decisions, and interventions into 12

appeals filed by others, have been filed with the Ninth Circuit Court of Appeals. Many of those appeals 13

have been consolidated, but each retains distinct issues within the consolidated dockets. 14

SCE’s economics experts have reviewed and analyzed the market participants’ data obtained 15

through discovery, compliance filings, Freedom of Information Act (FOIA) requests, fuel, emissions, 16

and cost filings by market participants, and market re-run data submitted by the California ISO and the 17

Power Exchange. Their economic analyses have been used to support testimony, protests and motions 18

at FERC, and appellate briefings at the Ninth Circuit. SCE’s consultants and outside counsel, working 19

in partnership with in-house counsel, have been instrumental in preserving the substantial balances in 20

the Power Exchange’s settlement clearing account and its collateral accounts, which has been used as a 21

source for the funding of settlements with multiple suppliers. 22

During the Record Period, the majority of the litigation and consultant costs were related to the 23

pursuit of settlements and the continued refund litigation at FERC related to the Summer Period and in 24

related lawsuits, including those that have resulted from the Ninth Circuit’s 2005 decision in Bonneville 25

Power Admin. v. FERC, 422 F.3d 908 (9th Cir. 2005). In that decision, the Ninth Circuit held that 26

under the Federal Power Act, FERC lacks jurisdiction to order refunds directly from governmental 27

165

power suppliers, but also observed that an alternative remedy for the California Parties may exist in the 1

form of a civil contract claim against the governmental suppliers. 2

In March 2006, SCE and the other IOU members of the California Parties filed an action in the 3

U.S. District Court for the Eastern District of California against a number of governmental entities that 4

sold power into the California markets during the energy crisis.146 This action was consolidated with a 5

similar action brought by SDG&E,147 but was dismissed by the district court without prejudice for lack 6

of federal subject matter jurisdiction. In April 2007, SCE and the other California Parties re-filed their 7

action in the Los Angeles County Superior Court. This action was coordinated with an action originally 8

brought by the California State Attorney General’s Office in the Sacramento County Superior Court.148 9

The coordinated proceeding (also designated as a complex litigation matter and referred to herein as the 10

“LA Action”) was assigned to the Central Civil West Courthouse. All the governmental agencies party 11

to the LA Action settled with the California Parties in 2011. The only remaining defendant in the LA 12

Action is the Arizona Electric Power Cooperative (AEPCO). The California Parties anticipate finalizing 13

a settlement agreement with AEPCO in 2013. 14

Additionally, SCE and other members of the California Parties continue to participate in a 15

parallel, contract-based action in the Court of Federal Claims (COFC) against two federal governmental 16

agency suppliers, Bonneville Power Administration (BPA) and Western Area Power Administration 17

(WAPA). In June of 2012, the judge in the case ruled in the Cal Parties’ favor on liability issues. The 18

trial on damages is set to commence in June 2013.149 19

146 Pacific Gas and Elec. Co., et al. v. Arizona Elec. Power Coop., Inc., et al. U.S.D.C., Eastern District of California,

Sacramento Division, Case No. 2:06-CV-0559-MCE-KJM. 147 San Diego Gas & Elec. Co. v. Arizona Elec. Power Coop., Inc., et al. U.S.D.C., Eastern District of California,

Sacramento Division, Case No. 2:06-CV-0592-MCE-KJM. 148 Pacific Gas and Elec. Co., et al. v. Arizona Elec. Power Coop., Inc., et al. (Los Angeles Superior Court Case No.

BC369141) and California ex rel. Lockyer v. Los Angeles Department of Water & Power (Sacramento Superior Court Case No. 06AS05354) Judicial Council Coordination Proceeding No. 4512.

149 Pacific Gas and Elec. Co., Southern California Edison Co., and California Electricity Oversight Board v. The United States, Case No. 07-157C and San Diego Gas & Elec. Co. v. The United States, Case No. 07-167C (Senior Judge Loren Smith).

166

During the Record Period, SCE was a Complainant in Commission hearings with regard to 1

wholesale spot market sales of electricity during the “Summer Period” (May 1, 2000 - October 1, 2000). 2

In 2009, the Ninth Circuit remanded the case back to FERC to consider relief on grounds that suppliers 3

committed various tariff violations creating unjust and unreasonable prices for California ratepayers.150 4

During the Record Period, SCE played a key role in providing evidence and testimony to the presiding 5

administrative law judge (ALJ). The ALJ’s February 15, 2013 Initial Decision (ID) 151 found in the 6

California Parties’ favor on most of the gaming and market manipulation charges for the Summer Period 7

presented in the California Parties’ case. However, FERC largely reserved for itself the role of 8

determining a remedy for these violations. It is important to note that the ALJ’s ID held that the 9

California Parties proved their case for certain transactions known as “Energy Exchanges” and “Forward 10

Transactions,” and adopted the California Parties’ calculation of $91 million in refunds for those 11

transactions. 12

7. Recovery of Amounts Recorded in the LCTA 13

As discussed below, SCE requests to recover the balance recorded in the LCTA as of December 14

31, 2012 (which already reflects only 90% of the total litigation costs), plus accrued interest, consistent 15

with the accounting methodology specified in Resolution E-3894.152 In Resolution E-3894, the 16

Commission determined that SCE’s litigation costs recorded in the LCTA should be reviewed in the 17

ERRA proceeding and, accordingly, has been reviewing these amounts in ERRA. 18

8. Conclusion and Request for Finding 19

During the Record Period, entries to the ESMA included: 20

� Settlement agreement refunds received 21

� Payment made to the Metropolitan Water District 22

150 Pub. Utils. Comm’n of Cal. v. FERC, 462 F.3d 1027 (9th Cir. 2006) (CPUC Decision). 151 San Diego Gas & Elec. Co. v. Sellers of Energy & Ancillary Servs., 142 FERC ¶ 63,011 (2013) (Initial Decision). 152 Interest will continue to accrue in the LCTA until the date the Commission allows recovery of the balance.

167

� 10% of net refunds retained as a shareholder incentive for Refund Period portions only of 1

“new” settlements, and for “old” settlements 2

In addition, SCE recorded energy crisis-related litigation costs and settlement effort costs in the 3

LCTA. SCE’s testimony demonstrates that amounts recorded in the ESMA and the LCTA during the 4

Record Period were reasonable, in compliance with Resolution E-3894, and were consistent with the 5

Settlement Agreement. Accordingly, SCE requests the Commission find amounts recorded in the 6

ESMA and the LCTA during the Record Period to be appropriate, correctly stated, consistent with 7

Commission orders, and reasonably incurred. Finally, SCE requests the Commission authorize SCE to 8

recover the 90% of litigation costs recorded in the LCTA as of December 31, 2012, which constitutes 9

the undercollected amount of $3.474 million in this account, plus accrued interest.10

168

XIII. 1

EDISON SMART CONNECT PROGRAM COSTS RECOVERY 2

A. Background and Ratemaking 3

SCE’s Advanced Metering Infrastructure (AMI) project, also known as Edison SmartConnect, 4

has resulted in the installation of 4.95 million smart meters in households and businesses with a demand 5

of less than 200 kW over the 2008-2012 period. SCE implemented the AMI project in three phases 6

(Phase I, II, and III) and its costs associated with this project are reviewed in SCE’s annual April ERRA 7

Review proceedings. The Commission has already reviewed SCE’s Phase I and Phase II recorded costs, 8

and some of its Phase III recorded costs, in prior ERRA Review proceedings.153 In this chapter, SCE 9

describes its ongoing Phase III recorded costs incurred during the 2012 Record Period. 10

The purpose of the Edison SmartConnect Balancing Account (ESCBA) is to record the revenue 11

requirement associated with Phase III costs incurred by SCE for deployment of Edison SmartConnect 12

meters. In D.08-09-039, the Commission approved Phase III funding for full deployment of Edison 13

SmartConnect and authorized the establishment of the ESCBA to recover costs up to $1,633.5 million 14

for AMI deployment activities over the 2008 – 2012 deployment period.154 In addition, the operation of 15

the ESCBA recognizes ratepayer operational benefits associated with the Edison SmartConnect project. 16

Specifically, SCE credits $1.4246 per meter of O&M operational benefits, per month, via the ESCBA 17

beginning eight months after each meter is received and recorded in rate base.155 18

On November 29, 2012, the Commission issued D.12-11-051 (SCE’s 2012 Test Year GRC 19

Decision). D.12-11-051 authorizes SCE to “continue the Edison SmartConnect Balancing Account 20

153 The Commission approved all of SCE’s Phase I and Phase II costs, and some of its Phase III recorded costs in D.07-12-

027, D.08-11-021, D.10-07-049, and D.11-10-002. SCE presented additional Phase III recorded costs in its April 2011 and April 2012 ERRA Review Applications, A.11-04-001 and A.12-04-001, which are currently pending before the Commission.

154 Up to $100 million in additional costs may also be recorded in the ESCBA, consistent with the terms and conditions of the risk-sharing mechanism for deployment cost overruns authorized in D.08-09-039. In addition, in SCE’s 2012 GRC Application (A.10-11-015), SCE requested that the ESCBA remain in operation in 2013 and 2014 for the purposes of recording certain costs approved in D.08-09-039. See A.10-11-015, Exhibit SCE-04, Volume 1, page 30.

155 See Section C of this chapter.

169

in this [2012] rate cycle and to record their expenses anticipated by D.08-09-039 for Home Area 1

Network (HAN) and related programs for Programmable Communicating Thermostats (PCT) and 2

In-Home Display (IHD) devices.”156 157 Such costs recorded in 2013 and 2014 in the ESCBA will 3

continue to be reviewed in SCE’s annual ERRA Review proceedings. 4

Pursuant to SCE’s approved preliminary statement, the Commission reviews the recorded 5

operation of the ESCBA in SCE’s annual ERRA Review proceedings to determine that the entries 6

recorded during the previous calendar year were stated correctly and incurred for SCE’s AMI Phase III 7

activities. The following section describes SCE’s entries recorded in the ESCBA in 2012. 8

B. Operation of the ESCBA 9

Each month, SCE records its actual revenue requirements associated with Phase III activities into 10

the ESCBA. These monthly entries consist of recorded O&M expenses and capital-related revenue 11

requirements (book depreciation, authorized return on recorded rate base, and applicable taxes). SCE 12

then transfers the amounts recorded in the ESCBA to the distribution sub-account of the BRRBA on a 13

monthly basis. Interest expense is not recorded in the ESCBA because the balance is transferred to the 14

BRRBA each month. 15

During the Record Period, SCE transferred $179.201 million from the ESCBA to the distribution 16

sub-account of the BRRBA. The table below summarizes recorded activity in the ESCBA for the 17

Record Period. 18

156 See D.12-11-051, OP 24, at page 884. 157 On November 23, 2010, SCE filed A.10-11-015 (SCE’s 2012 General Rate Case (GRC) Application), in which SCE

requested that the ESCBA “remain in operation for purposes of recording authorized [HAN and related PCT and IHD] costs that are expected to be incurred in 2013 and 2014.” See A.10-11-015, SCE-04, Volume 1, Chapter VII, page 30.

170

Table XIII-50 Edison SmartConnect Balancing Account

C. Edison SmartConnect Operational Benefits 1

The settlement agreement approved in D.08-09-039 provides that SCE will credit $1.4246 per 2

meter of O&M operational benefits per month during the deployment period, beginning eight months 3

after the meter is reflected in rate base. The first meters were purchased and recorded into rate base in 4

June 2009. Therefore, the operational benefit credits began accruing to the ESCBA in February 2010 5

and continued each month based on the cumulative number of meters purchased eight months 6

previously. During the Record Period, as shown above on Line 5 of Table XIII-50, a total of $64.699 7

million of operational benefit credits were transferred from the ESCBA to the BRRBA to be included in 8


1 . B e ginning B a la nc e -

2 . O p e ra ting E xp e nse s3 . R e c o rd e d O & M 9 4 ,9 3 7 4 . Ind ire c t L a b o r 4 ,0 2 7 5 . O p e ra tio na l B e ne fit C re d its (6 4 ,6 9 9 ) 6 . T o ta l O p e ra ting E xp e nse s 3 4 ,2 6 4

7 . C a p ita l- R e la te d R e ve nue R e q uire m e nt8 . D e p re c ia tio n 8 0 ,5 7 1 9 . T a xe s 4 ,3 6 6

1 0 . R e turn 6 0 ,0 0 0 1 1 . T o ta l C a p ita l- R e la te d R e ve nue R e q uire m e nt 1 4 4 ,9 3 7

1 2 . (O ve r)/U nd e r C o lle c tio n (L ine 6 + L ine 1 1 ) 1 7 9 ,2 0 1

1 3 . T ra nsfe r to B R R B A (D .0 8 - 0 9 - 0 3 9 ) (1 7 9 ,2 0 1 )

1 4 . E nd ing B a la nc e -

171

distribution rate levels. The operational benefit credits are based on monthly cumulative meter 1

purchases, which totaled $4.568 million as of April 2012.158 2

D. Edison SmartConnect Capital Benefits 3

In D.08-09-039, the Commission established a mechanism for the recognition of capital benefits 4

resulting from the Edison SmartConnect project. Pursuant to the established ESCBA Preliminary 5

Statement, Part QQ, all capital-related benefits are to be returned to customers during the deployment 6

period through the operation of the BRRBA. In D.12-11-051 (SCE’s 2012 GRC decision), the 7

Commission adopted a capital benefits forecast of $9.682 million for the Edison SmartConnect project 8

for 2012. When SCE filed its 2012 GRC Compliance Advice Letter 2826-E on December 19, 2012, the 9

Authorized Distribution Base Revenue Requirement in the BRRBA reflected the dollars that the 10

Commission authorized SCE to collect from ratepayers, net of the ESC capital benefits for 2012.159 11

E. Description of Phase III Costs 12

The Phase III Edison SmartConnect full deployment activities include the following functional 13

cost categories that were authorized in D.08-09-039:160 14

� Acquisition of meters and communication network equipment. 15

� Installation of meters and communication network equipment. 16

� Implementation and operation of new back office systems. 17

� Customer tariffs, programs and services. 18

� Customer service operations. 19

� Overall program management. 20

� Contingencies for mass meter deployment. 21

158 Per the settlement agreement approved in D.08-09-039, meters purchased in April 2012 would record operational

benefits in eight months, or in December 2012. 159 Since SCE is required to credit customers the ESC capital related benefits, for administrative ease SCE included the

2012 ESC capital related benefits forecast in the 2012 GRC revenue requirement (A.10-11-015). As such, SCE did not record the 2012 capital related benefit in the BRRBA.

160 Recorded costs in 2012 include $3.507 million in severance payment costs for Field Service Representatives and Meter Readers who were voluntarily or involuntarily reduced at the end of Smart Meter deployment.

172

SCE began its Phase III deployment activities in 2008 and continued these activities through 1

2012. During the Record Period, SCE recorded revenue requirements in the ESCBA related to 2

expenditures incurred for the authorized Phase III deployment activities that are shown in the following 3

table.161 4

Table XIII-51 Edison SmartConnect Phase III 2012 Expenditures ($000)

In D.08-09-039, the Commission authorized a total Phase III deployment funding level of 5

$1,633.5 million, which is subject to a $100 million cost over-run provision. As shown in the table 6

above, 2008 to 2012 Phase III costs totaled $1,540.8 million. In the following sections, SCE describes 7

its 2012 expenditures by functional cost category. 8

161 The costs of medical, pensions, and post-retirement benefits other than pensions (PBOPs), are not recovered through the

ESCBA and are recovered in a separate balancing account. The revenue requirements associated with all other amounts shown are recovered through the ESCBA.

Categories O&M Capital Total Line No Edison SmartConnect Key Deployment Functional Area

1 Direct Expenditures: 2 Acquisition of meters and communication network equipment 8,873 137,067 145,940 3 Installation of meters and communication network equipment 20,119 78,497 98,616 4 Implementation and operation of new back office systems 22,363 68,880 91,243 5 Customer tariffs, programs and services 14,381 14,381 6 Customer service operations 13,054 32 13,086 7 Overall program management 10,812 (69) 10,743 8 Unrealized benefits - Program contingency 5,335 5,335 9 Subtotal – direct expenditures 94,937 284,408 379,345

10 Labor loadings (based on GRC authorized rates): 11 Pensions 2,718 4,068 6,786 12 PBOPs 861 1,290 2,151 13 Medical 2,462 3,685 6,147 14 401(k) 1,235 1,848 3,083 15 Payroll taxes 2,108 3,162 5,269 16 Disability programs 456 683 1,139 17 Worker’s compensation 229 342 571 18 Capital, administrative, and general 9,469 9,469 19 Subtotal – labor loadings 10,068 24,548 34,616

20 Total 2012 expenditures (Line 9 + Line 19) 105,005 308,955 413,960 21 Total 2008 to 2011 expenditures 183,765 943,041 1,126,807 22 Total Phase III expenditures (Line 20 + Line 21) 288,770 1,251,997 1,540,767

173

1. Acquisition of Meters and Communication Network Equipment 1

The acquisition of Meters and Communication Network Equipment category consists primarily 2

of costs related to Edison SmartConnect meters and communication infrastructure equipment. The 3

Edison SmartConnect meter records electricity usage that is retrieved periodically through the 4

communications network equipment. The communications network enables two-way communications 5

between the Edison SmartConnect meter and SCE’s back office systems. SCE estimates that 95% of the 6

costs in this category were for purchasing meters and the communication network equipment, with the 7

remaining costs associated primarily with vendor management and meter acceptance testing. 8

In 2012, SCE purchased approximately 1.04 million meters to support mass meter deployment. 9

Recorded costs in this category were $145.9 million, which is comprised of $137 million in capital 10

expenditures and $8.9 million in O&M expense. 11

2. Installation of Meters and Communication Network Equipment 12

The installation of Meters and Communication Network Equipment category consists primarily 13

of the labor costs required to install the Edison SmartConnect meters and communication network 14

equipment. In 2012, SCE successfully installed approximately 1.18 million Edison SmartConnect end-15

point meters and approximately 2,200 cell relays throughout the SCE service territory, utilizing the SCE 16

installation vendor system interfaces and the vendor’s work and inventory management system. 17

Accomplishing this required SCE to manage its deployment vendor resources and SCE personnel to 18

support an average of over 4,400 meter installations per installation day. Recorded costs in this category 19

were $98.6 million, including $78.5 million in capital expenditures related to the installation vendor’s 20

costs, and $20.1 million in O&M expense related to SCE’s labor costs. 21

3. Implementation and Operation of New Back Office Systems 22

The implementation and operation of New Back Office Systems category is comprised of costs 23

associated with defining business requirements, designing systems, partnering with vendors, and 24

developing, integrating, testing, and installing systems supporting the Edison SmartConnect program. 25

Critical components of SCE’s back office systems include the network management system (NMS), the 26

meter data management system (MDMS), Operational Center system, Home Area Network (HAN) with 27

174

load control system and the data warehouse, as well as legacy systems such as the customer service 1

system (CSS) and SCE.com. 2

SCE incurred the majority of 2012 costs in this category in order to enhance interval billing and 3

data warehouse functionality, which include the development of the Edison SmartConnect MDMS, Data 4

Warehouse, Web Presentment, Interim HAN, and operational systems, and to implement Edison 5

SmartConnect Monitoring & Analysis and HAN with load control capabilities. These implementation 6

activities include planning, development, system testing, and project rollout. The 2012 costs also 7

include activities related to developing the business and technical requirements for firmware upgrades 8

that will enhance network performance, enable the remote service switch, enable firmware download 9

automation and cell relay configuration management, provide outage information, enable the 10

deployment of the second meter vendor, and support security event monitoring. The 2012 costs for the 11

Edison SmartConnect Operations Center, which oversees the operations of the Edison SmartConnect 12

smart meter communications network, are also included in this category. Recorded costs for this 13

category were $91.2 million in 2012. This amount includes $68.9 million in capital costs for the 14

MDMS, Data Warehouse, Web Presentment Systems, and the Edison SmartConnect Operations Center, 15

as well as $22.4 million in related O&M expense. 16

4. Customer Tariffs, Programs, and Services 17

The Customer Tariffs, Programs, and Services category covers the costs associated with 18

researching, designing, and marketing Edison SmartConnect-enabled rates, programs, and services. In 19

2012, SCE saw an increase in customers who were able to participate in Edison SmartConnect-enabled 20

programs and services as full functionality rolled out to 4.9 million customers throughout SCE’s service 21

territory. Customer Tariffs, Programs, and Services costs for 2012 include developing program 22

education tools (e.g., online customer communications and outreach materials in multiple languages) 23

and meter installation communications, conducting market research to enhance new programs and 24

customer communications, and enhancing web-based information and tools to encourage customers’ 25

participation in SCE’s programs and services, including Save Power Day Event Notifications, which has 26

175

over 825,000 participating customers. Recorded O&M expense for this category in 2012 was $14.4 1

million. 2

5. Customer Service Operations 3

The Customer Service Operations category contains the costs of integrating Edison 4

SmartConnect into SCE’s existing customer service operations. In 2012, costs in this category include 5

creating business requirements in support of customer billing, system testing, and performing rate 6

analysis for non-residential customers. Also included in this category are operational oversight and 7

activities involving analyzing and processing interval usage data, billing exception processing, handling 8

Edison SmartConnect-related customer phone calls and training for customer service operations 9

employees. Total recorded costs for this category were $13.08 million in 2012, which consisted of 10

$0.03 million in capital costs for the construction of a new facility, and $13.05 million in O&M expense. 11

6. Overall Program Management 12

The overall Program Management category contains the costs for oversight of the Edison 13

SmartConnect deployment program throughout the deployment period, including program management, 14

program planning, finance and budget development, audit preparation, management, and support, 15

internal controls development and testing, regulatory compliance activities, and facility costs for the 16

Edison SmartConnect project resources. Recorded costs for this category were $10.7 million in 2012. 17

This amount includes ($0.07) million in capital costs resulting from an adjustment in prior year facilities 18

improvement expenses, as well as $10.8 million in related O&M expense. 19

7. Unrealized Benefits - Program Contingency 20

D.08-09-039 permits SCE to utilize project contingency for any unanticipated Edison 21

SmartConnect deployment costs, whether resulting from increases in estimated costs, or from 22

unanticipated delays in realizing benefits from meter deployment.162 During the Record Period, due to 23

162 The use of contingency funds for unrealized benefits was affirmed as a reasonable, uncontested issue in the DRA/SCE

Settlement Agreement that was fully adopted by the Commission in D.08-09-039. See D.08-09-039, which adopted the Settlement Agreement between DRA and SCE, including the utilization of project contingency for increases in estimated costs, or for unanticipated delays in realizing benefits from meter deployment. See also, A.07-07-026, Errata to Volume 2, page 78 for a description of how contingency funds may be used. See also, A.07-07-026, March 13, 2008 Hearing

(Continued)

176

unanticipated delays in realizing benefits as described below, the Edison SmartConnect program did not 1

realize $5.335 million in operational benefits. Consistent with D.08-09-039, SCE recorded such costs to 2

the program contingency cost category. Contributing factors to the delay in operational benefits include 3

incremental labor due to partially-deployed districts, deployment plan changes, hard-to-reach and non-4

communicating meters, and reduced operational benefits due to Commission decisions suspending use 5

of the remote service switch for credit operations and requiring a smart meter installation delay list. The 6

above factors produced an inability to reduce field services labor to the extent planned. Additional field 7

service visits were required to perform meter exchanges and pick-up meter reads. 8

F. Conclusion 9

SCE respectfully requests the Commission to find that the Phase III costs recorded in the 10

ESCBA during the Record Period were properly recorded and consistent with the categories adopted in 11

D.08-09-039. 12

Continued from the previous page Transcripts, in which SCE clarified that if for some reason it is not possible to achieve the estimated operational benefits, SCE may use the contingency allowance to cover the cost of the per-meter credits to ratepayers.

177

XIV. 1

MARKET REDESIGN AND TECHNOLOGY UPGRADE MEMORANDUM ACCOUNT 2

A. The CAISO’s Market Redesign and Technology Upgrade 3

1. Introduction 4

Pursuant to Resolution E-4087, SCE established the Market Redesign and Technology Upgrade 5

(MRTU) Memorandum Account (MRTUMA) to record incremental capital-related revenue requirement 6

and operations and maintenance (O&M) expenses associated with implementing the California 7

Independent System Operator’s (CAISO) MRTU initiative. In the MRTUMA, SCE records its initial 8

MRTU implementation and operating costs, as well as its costs associated with effecting ongoing 9

modifications and enhancements to the CAISO markets. MRTU and subsequent CAISO market 10

initiatives were mandated by the Federal Energy Regulatory Commission (FERC). 11

Pursuant to prior Commission decisions and orders,163 in this testimony SCE establishes that the 12

amounts recorded in the MRTUMA are incremental and verifiable (i.e., what SCE’s MRTU-related 13

activities are and what those activities cost).164 14

2. Summary of Request 15

In this proceeding, SCE is requesting Commission approval to recover approximately $2.42 16

million of its incremental and verifiable O&M costs recorded in the MRTUMA during the Record 17

Period. These O&M costs were incurred during the Record Period, and cover SCE’s additional 18

operating costs (e.g., additional personnel and maintenance costs for computer hardware and software) 19

incurred to implement MRTU and subsequent initiatives. SCE’s incremental O&M costs are 20

summarized below in Table XIV-52. 21

163 See Resolution E-4087, D.09-03-025, and D.09-12-021. 164 In its April 2010 ERRA Review Application, A.10-04-002, SCE explained the background of the MRTUMA, the MRTU

market structure, and SCE’s implementation of MRTU. See SCE’s direct testimony in A.10-04-002, Exhibit SCE-2, Chapter XV, Sections A-B.

178

Table XIV-52 Summary of MRTU Expense Request

In addition, SCE is requesting: 1) approval of $1.02 million of MRTU-related direct capital costs 1

incurred on the MRTU project, and 2) approval that these capital costs and associated overhead costs are 2

to be included in the capital base used in determining the capital revenue requirement recorded in the 3

MRTUMA. Based on the total MRTU-related capital base, SCE recorded a capital-related revenue 4

requirement (i.e., depreciation, return on rate base, and taxes) in the MRTUMA in the amount of $4.63 5

million in 2012. 6

SCE’s capital expenditures were incurred for infrastructure expansion and to implement the 7

following releases of the MRTU project during 2012: 8

� Winter Release 2011 9

� Spring Release 2012 10

SCE’s capital costs cover the modifications and testing of the computer systems that were 11

installed for MRTU go-live to handle the additional market changes that were implemented by the 12

various CAISO market initiatives. The capital costs are depreciated over the project lifecycle (five years 13

for computer software and hardware). Table XIV-53 below summarizes the MRTU-related direct 14

capital costs that SCE incurred during the Record Period. These capital costs and associated overhead 15

costs are the appropriate capital base used in determining the capital revenue requirement recorded in 16

the MRTUMA that will be recovered over the project life. 17

O & M(M illio n s )

ITIT Ma in te n a n c e 6 .2 8$

L e s s : N o n -In c re m e n ta l E xp e n s e s 3 .7 5$ L e s s : F E R C Ju r is d ic tio n a l Am o u n t 0 .1 1$

In c re m e n ta l R e c o rd e d O & M E x p e n s e s 2 .4 2$

179

Table XIV-53 Summary of MRTU Direct Capital Request

3. SCE’s Expenses Are Incremental and Verifiable 1

Per the Commission’s guidance, SCE’s testimony shows that the expenses incurred in 2

implementing MRTU are incremental and verifiable.165 That is, SCE demonstrates that these costs are 3

related to implementing MRTU initiatives and operating in the MRTU market and, in the case of SCE’s 4

MRTU-related O&M costs, above what was included in SCE’s 2012 General Rate Case (GRC), D.12-5

11-051. 6

SCE’s testimony covers two major cost areas: capital and O&M. SCE’s capital costs are 7

categorized by CAISO market initiatives. SCE’s O&M costs cover IT maintenance costs. 8

SCE is also providing the Commission with supporting workpapers for this testimony. These 9

workpapers contain extensive documentation verifying that SCE’s expenses were incurred to operate in 10

the MRTU market and to implement the CAISO’s MRTU initiatives. The workpapers explain in detail 11

each cost item that is included in this testimony, and can be used to trace SCE’s incurred costs to 12

individual vendor invoices, as well as to the time that each SCE employee and contractor spent on the 13

project. 14

165 The Commission’s decision in PG&E's ERRA Forecast proceeding, D.09-12-021 states the following (emphasis added):

“… the Commission notes that the scope of its review of PG&E’s MRTU costs is not necessarily a traditional reasonableness review. The MRTU project is a project mandated by regulatory and reliability requirements of the California Independent System Operator and Federal Energy Regulatory Commission. Therefore, the Commission expects the review of these costs to primarily focus on whether the costs can be verified and are incremental.”

Capital Core Workstreams ($Millions)

Winter 2011 Release (WR) $ 0.19

Spring 2012 Release (SR) $ 0.64

Infrastructure Expansion (HW) $ 0.20

Overall Result (WR + SR + HW) $ 1.02

180

B. Capital Costs 1

1. Introduction 2

The new MRTU market initiatives added increased complexity to the MRTU market and, as a 3

consequence, SCE’s internal processes for operating under MRTU. This increased complexity was the 4

primary driver of SCE’s capital spending during the Record Period. SCE managed its project costs by 5

tracking them according to CAISO initiatives. SCE’s MRTU core workstream activities and related 6

costs are summarized in Table XIV-54 below, and explained in the following sections: 7

Table XIV-54 Summary of Total Capital Costs ($Millions)

2. Winter 2011 Release 8

a) Summary of Costs 9

The Winter Release workstream covered the implementation of the CAISO Winter 2011 10

Release. The Winter Release workstream’s specific functions are discussed below. The incremental 11

Winter Release related costs incurred by year are as follows: 12

Table XIV-55 Summary of Winter Release-Related Costs ($Millions)

Core Workstreams 2012

Winter 2011 Release (WR) $ 0.19 Spring 2012 Release (SR) $ 0.64 Infrastructure Expansion (HW) $ 0.20 Overall Result (WR + SR + HW) $ 1.02

Winter 2011 Release (WR) 2012

Labor $ 0.07 Contract and Expenses $ 0.12 Total (Labor + Contract and Expenses) $ 0.19

181

b) Resources 1

As explained in the following sections, the Winter Release workstream was staffed with a 2

combination of SCE personnel and consultants and temporary staff from Cognizant Technology, Infosys 3

and Patni. SCE personnel were used for project management, system configuration, testing, market 4

simulation and implementation. Over 12 SCE employees worked in the Winter Release workstream 5

during the project for a total cost of $0.07 million. 6

Contractors from Infosys were used for software analysis, design, development and testing, 7

system integration, and software quality assurance of the IT development effort, and supporting the 8

CAISO market simulation. The total amount spent on Infosys was . 9

Contractors from Cognizant Technology and Patni were used for technical architecture, system 10

installation of the Power-Costs, Inc. (PCI) software, configuration and customization of the PCI 11

software. The total amount spent on these contractors was . 12

c) Scope of Work 13

The Winter 2011 Release workstream involved the development of business processes and the 14

modification of existing software products to enable Power Procurement to implement the market 15

initiatives in the CAISO Winter 2011 Release. The implementation of each of these initiatives is 16

discussed below. 17

(1) GMC166 Rate Structure 18

The PCI system and related reports were modified to implement the new settlement charge codes 19

from the new CAISO GMC rate structure. The system modifications were tested through IT system 20

testing, user testing, and active participation in the CAISO market simulation. 21

166 GMC stands for Grid Management Charge, which is one of the ways that CAISO charges market participants for its

services.

182

(2) Generated Bids and Outage Reporting for Non-Resource Specific 1

Resource Adequacy (NRS-RA) Resources 2

The PCI system and related system interfaces and reports were modified to manage outages for 3

NRS-RA resources and to process the new NRS-RA settlement charge codes. The system modifications 4

were tested through IT system testing, user testing, and active participation in the CAISO market 5

simulation. 6

(3) Multi-Stage Generator (MSG) Phase 1 7

This initiative did not require SCE to modify software or system interfaces. The existing 8

systems were tested through IT system testing and user testing to ensure that no issues would arise due 9

to the CAISO changes. In addition, SCE participated actively in the CAISO market simulation to 10

validate the CAISO systems and market results. 11

(4) Flexible Ramping Constraint 12

The PCI system and related system interfaces and reports were modified to implement the new 13

settlement charge codes from the CAISO Flexible Ramping Constraint initiative. The system 14

modifications were tested through IT system testing, user testing, and active participation in the CAISO 15

market simulation. 16

(5) Grouping Constraints 17

The PCI system and related system interfaces and reports were modified to handle grouping 18

constraints (operating constraints that span multiple physical generating units). The system 19

modifications were tested through IT system testing, user testing, and active participation in the CAISO 20

market simulation. 21

3. Spring 2012 Release 22


The Spring Release (SR) workstream covered the implementation of the CAISO Spring 2012 24

Release. The Spring Release workstream’s specific functions are discussed below. The incremental 25

Spring Release related costs incurred by year are as follows: 26

183

Table XIV-56 Summary of Spring Release-Related Costs ($Millions)

b) Resources 1

As explained in the following sections, the Spring Release workstream was staffed with a 2

combination of SCE personnel and consultants and temporary staff from @Business, Cognizant, 3

Infosys, and Patni. SCE personnel were used for project management, system configuration, testing, 4

market simulation and implementation. Over 19 SCE employees worked in the Spring Release 5

workstream during the project for a total cost of $0.41 million. 6

Contractors from @Business, Cognizant, and Patni were used for documenting business process 7

requirements, software analysis, design, development and testing, system integration, technical 8

architecture, and software quality assurance of the IT development effort, system installation of the PCI 9

software, configuration and customization of the PCI software, developing and testing the PCI system 10

modifications and the system interfaces between the PCI software and the other software at SCE, and 11

supporting the CAISO market simulation. PCI provided implementation and configuration services for 12

their software package. The total amount spent on these contractors was . 13

Contractors from Infosys were used for software analysis, design, development and testing, 14

system integration, and software quality assurance of the IT development effort, and supporting the 15

CAISO market simulation. The total amount spent on Infosys was . 16

c) Scope of Work 17

The Spring 2012 Release workstream involved the development of business processes and the 18

modification of existing software products to enable SCE’s Power Procurement Department to 19

implement the market initiatives in the CAISO Spring 2012 Release. The implementation of each of 20

these initiatives is discussed below. 21

Spring 2012 Release (SR) 2012


184

(1) Multi-Stage Generator (MSG) Phase 2 1

The PCI system and related system interfaces and reports were modified to implement the 2

settlement charge codes for the Multi-Stage Generator market initiative. The system modifications were 3

tested through IT system testing, user testing, and active participation in the CAISO market simulation. 4

(2) Non-Generating Resource/Regulation Energy Management Phase 1 5





(3) Local Market Power Mitigation Enhancements Phase 1 10





(4) Default O&M Adder 15


systems were tested through Information Technology (IT) system testing and user testing to ensure that 17

no issues would arise due to the CAISO changes. In addition, SCE participated actively in the CAISO 18

market simulation to validate the CAISO systems and market results. 19

(5) Enhancements to Virtual Bidding Software 20

In addition to the CAISO market initiatives described above SCE developed and implemented 21

enhancements to software originally implemented to support the CAISO Virtual Bidding initiative. 22

Virtual Bidding went live in 2011 and was described in section XVI.B.3 of the SCE 2012 ERRA filing, 23

A.12-04-001. Operational experience from the Virtual Bidding market caused SCE to identify needed 24

system enhancements in the Price Forecasting and Market Analysis area. 25

185

The system and user interfaces to automatically collect and assemble daily data sets for the 1

Power-GEM PROBE market simulation tool167 were modified and enhanced to support operational 2

needs in the Virtual Bidding market. The system modifications were tested through IT system testing 3

and user testing. 4

4. Infrastructure Expansion 5

The infrastructure established for the MRTU systems needed to be expanded / upgraded to 6

handle the growing data volumes produced by the new CAISO initiatives. 7


The incremental costs for this workstream incurred by year are as follows: 9

Table XIV-57 Summary of Infrastructure Expansion Costs ($Millions)

b) Resources 10

The amount spent by the infrastructure expansion workstream was for purchasing the hardware 11

needed to expand the infrastructure that was put in place for MRTU go-live in April 2009. 12

The infrastructure expansion workstream was staffed by SCE personnel, and temporary staff 13

from @Business. SCE personnel were used for project management, architecture, and installation. 14

Over three SCE employees worked in the infrastructure expansion workstream during the project for a 15

total cost of less than $0.01 million. In addition, $0.19 million was incurred for hardware, operating 16

software, storage and miscellaneous expenses. 17

167 This system was described in section XVI.B.3.c.1 of the SCE 2012 ERRA filing, A.12-04-001, SCE-2, p.185.

Infrastructure Expansion (HW) 2012


186

@Business was used for installation of servers, operating systems, applications and management 1

of databases. The total amount spent for @Business was less than2

c) Scope of Work 3

The scope of work for this workstream included: 4

� Adding memory and storage to the MRTU computer systems. 5

� Purchasing licenses for Oracle database compression software that enables more effective 6

utilization of storage space 7

C. O&M Costs 8

1. Introduction 9

In 2012, SCE incurred $6.28 million in incremental IT maintenance costs. As discussed in 10

Section D below, SCE is only requesting to recover $2.42 million of its total O&M costs, which is 11

incremental to the amount authorized in the 2012 GRC. SCE’s O&M costs are summarized in Table 12

XIV-58 below: 13

Table XIV-58 Summary of O&M Costs ($Millions)

2. IT Maintenance Costs 14

This chapter explains SCE’s 2012 IT maintenance costs required to support the MRTU software 15

and hardware. These costs totaled $6.28 million and fall into two categories: (1) annual license renewals 16

and (2) labor. SCE’s IT Department uses standardized processes and industry best practices to ensure 17

maintenance is performed consistently across SCE’s various business units and technology platforms. 18

SCE’s IT Department uses SAP enterprise work management software, which allows it to track MRTU 19

costs and labor effort on work orders separate from other IT maintenance activities. 20

Labor

Contract and Expenses

Total (Labor + Contract and Expenses)

IT Maintenance $ 1.66 $ 4.62 $ 6.28 Total (IT Maintenance) $ 1.66 $ 4.62 $ 6.28

187

a) License Renewal 1

In 2012, SCE incurred $1.84 million in MRTU software license renewal costs. SCE’s software 2

purchase contracts require SCE to pay annual license renewal fees in order to receive software upgrades 3

and product support from the software vendor. SCE capitalized its MRTU hardware license costs as 4

part of its original procurement, so these costs are not included in maintenance. 5

Software license renewals normally occur on a yearly basis, starting from the date the software 6

was put into production. Table XIV-59 shows the breakdown of all MRTU software license renewals 7

incurred in 2012: 8

Table XIV-59 MRTU Software License Renewal Costs

Vendor Description

2012 License Renewal

Cost

IBM AMPL Support

ITRON Inc. Metrix-IDR System Maintenance Power Costs Inc. PCI Licenses & Maintenance Power Costs Inc. PCI PIRP Maintenance & Support POWERGEM Probe Licenses Ventyx Energy EV Energy Map Ventyx Energy EV Market Op Ventyx Energy EV Power with New entrants Ventyx Energy FTR Trader Ventyx Energy Velocity Suite Online Ventyx Energy Enterprise ISO Ventyx Energy Enterprise Generation Management Ventyx Energy Gridview (renewal for 2011) Ventyx Energy Gridview (renewal for 2012) Czarnecki-Yester Consulting Group Settlement Allocations Service Fee EnDimensions, LLC Settlement Services Fee Power Settlements Software Licenses & Maintenance SCE Procurement Service Fee Total $1,837,968

188

Software license costs can increase over time due to normal escalation defined in the software 1

purchase contracts. In 2012 SCE spent for PCI Licenses and Maintenance fees. These fees 2

cover 24/7 problem diagnostics and troubleshooting, software maintenance, and software fixes from PCI 3

to address defects with all software modules installed at SCE. They also cover software product releases 4

which include general technology and business function upgrades provided to PCI’s entire customer 5

base. 6

SCE spent on Czarnecki-Yester Consulting Group (CY-CG) services in 2012. CY-7

CG provides settlement allocations functionality on a service basis. This service is described in more 8

detail in section XVI.C.3.d.1 in the SCE ERRA filing for 2011 MRTU expenses (A.12-04-001). 9

SCE spent on Power Settlements license and maintenance fees for software that is 10

used to analyze and review CAISO operational events from the prior operating day. This software, 11

which is referred to as Market Operations Settlement Analysis Information Center (MOSAIC), is 12

described in more detail in section XVI.C.3.d.2 in the SCE ERRA filing for 2011 MRTU expenses. 13

The Czarnecki-Yester Consulting Group, EnDimensions and Power Settlements expenses were 14

originally booked to the Power Procurement MRTU-incremental O&M accounts. As part of corporate 15

reorganization and streamlining efforts the responsibility and budget for managing all technology 16

services, license and maintenance contracts was moved to the IT organization. Since Czarnecki-Yester 17

Consulting Group, EnDimensions and Power Settlements provide technology services, SCE has 18

included these expenses as part of the IT MRTU-incremental O&M expenses in this filing. 19

b) Labor Costs 20

MRTU IT maintenance functions are performed by the software support and server hardware 21

support groups within the SCE IT Department. In 2012, SCE incurred $4.44 million in MRTU IT 22

maintenance labor costs. This includes SCE and contractor labor costs to maintain MRTU software, 23

hardware, and system integration technologies. 24

The MRTU project implemented a complex IT environment which must support a 24/7 mission 25

critical business operation (i.e., daily, around-the-clock, critical operations). This requires dedicated, 26

professional staff who can quickly respond to a broad range of potential technical and operational 27

189

problems. IT also requires a knowledgeable support staff who can respond to new CAISO market 1

changes within externally-driven time lines which are often quite short. Follow-on MRTU market 2

initiatives added new system functionality to the complex MRTU IT environment. 3

(1) Software Maintenance Costs 4

In 2012, the software maintenance group incurred $4.27 million in IT labor costs and 76,772 in 5

effort hours to support MRTU software, database, and system integration technologies. The software 6

support group is the largest IT maintenance group dedicated to Power Procurement and support of the 7

CAISO MRTU energy markets. This group’s maintenance activities include continuous application 8

performance monitoring, database performance monitoring, defect repair, system enhancements, and 9

technical upgrades. 10

The MRTU project implemented a robust and complex system architecture to support the 11

portfolio of MRTU energy planning, scheduling, settlements, and market monitoring business software 12

applications. IT continuously monitors all of the MRTU business software applications, databases, and 13

the 344 system interfaces which process the MRTU market data. The scope of business software 14

applications includes all of the purchased vendor software as well as the two software applications 15

developed internally by SCE: (1) the Common Data Store (CDS) and Power Procurement Data and 16

Reporting (PDR). In addition to the CDS and PDR software applications, SCE worked with PCI to 17

jointly develop the contract allocations module and operations reporting capabilities using the Business 18

Intelligence Reporting Tool (BIRT). This custom software code is supported primarily by the software 19

maintenance group with only limited assistance from PCI. 20

Because of the dynamic nature of the CAISO business environment and the high volume of time-21

critical planning, scheduling, and settlements market transactions, the software maintenance group must 22

continuously monitor critical software applications and system interfaces in order to rapidly respond to 23

problems and system defects. Defects can be caused by vendor code problems, SCE code problems, 24

CAISO code problems, and bad data. To provide 24/7 support for the critical MRTU software 25

applications, SCE requires a team of IT maintenance professionals with expertise in systems analysis, 26

190

development, database management and testing. This includes technical skills in Java web services, 1

Microsoft .Net (dot Net), IBM DataStage, Business Objects, Oracle, and SQL Server. 2

To ensure MRTU software defect fixes and system enhancements meet the documented business 3

requirements and do not introduce new problems, the software maintenance group supplements its 4

testing resources for MRTU. Each major release of the PCI software requires multiple iterations of 5

extensive testing over a several-week period to identify and resolve any defects prior to implementing 6

the software in SCE’s production IT environment. This is a key example of the software maintenance 7

team’s diligent work to prevent software defects from impacting critical MRTU business processes. 8

In performing MRTU maintenance activities, the software support group follows rigorous 9

Sarbanes-Oxley (SOX) processes to ensure data and reporting integrity. It also follows industry 10

standard IT Infrastructure Library (ITIL) change control and release management processes to protect 11

the integrity of the SCE IT technology environment. Both SOX and ITIL require extensive 12

documentation and technical reviews. 13

In addition to performing routine software defect fixes and minor software enhancements, the 14

software maintenance group has to support major software version changes and technology upgrades. In 15

2012, the software support group upgraded the PCI software to a new, major release. This new version 16

integrated our SCE code base into the PCI standard code base. In all, this major version contained 321 17

change requests and required substantial testing throughout the implementation. The Oracle database 18

software supporting MRTU was also upgraded from version 10 to version 11. These efforts required the 19

planning, development and testing rigor of a project. The software maintenance group also supported 20

the upgrade of 117 MRTU reports from version 3.3 to version 4.0 of the Business Objects reporting tool. 21

This upgrade was a significant effort because all of these reports needed to be individually modified for 22

the new Business Objects version and thoroughly tested. 23

191

(2) Server Hardware Maintenance 1

The server hardware group incurred $0.17 million in IT labor costs and 2,638 in effort hours 2

during the Record Period. This group is responsible for: (1) maintenance of MRTU UNIX168 server 3

hardware, Windows server hardware, and web application servers; (2) monitoring all server hardware 4

and server operating systems for any defects or performance issues which could impact time critical 5

MRTU business processes; (3) managing the remote failover technology which enables the MRTU 6

disaster recovery and business continuity capability between the Power Procurement home office in 7

Rosemead, California and the backup facility in Irvine, California; and (4) ensuring the routine 8

operational batch jobs execute with no issues, including the daily system backups. In 2012, some of the 9

server hardware was upgraded supporting the test and production environments for the MRTU 10

applications, such as the UNIX server hardware supporting the Oracle database environments for the 11

MRTU applications Common Data Store (CDS), Power Procurement Data and Reporting (PDR), Power 12

Procurement Suite (PPT), Itron Price Forecasting, and Probe. 13

The server hardware group also supports the IBM WebSphere and Oracle WebLogic servers. 14

The WebSphere server runs the Java-based web service code used by SCE’s internally developed CDS 15

software application. The WebLogic server runs the Java-based web service code used by the purchased 16

PCI applications. The server hardware group’s maintenance of WebSphere and WebLogic includes 17

technology upgrades. The group also monitors these web servers on a routine basis and works to 18

quickly address any time-sensitive issues. Time-critical MRTU system interfaces run on the WebSphere 19

platform, and there have been cases where a MRTU transaction has become “hung-up” on the web 20

server creating a transaction backlog. These situations require a timely response from the server 21

hardware support group. 22

168 UNIX is one of the operating systems used on SCE’s computer servers.

192

D. Summary of Entries Recorded in the MRTUMA 1

Consistent with Resolution E-4087, D.09-06-025, D.12-11-051, Advice 2826-E169 and SCE’s 2

Preliminary Statement Part N.41, MRTUMA, SCE recorded incremental CPUC-jurisdictional O&M 3

expenses in the amount of $2.418 million and a CPUC-jurisdictional capital revenue requirement total of 4

$4.626 million in the MRTUMA during this Record Period. SCE’s requested incremental O&M and 5

capital revenue requirements are summarized in Table XIV-60 below. 6

Table XIV-60 Market Redesign and Technology Upgrade Memorandum Account (MRTUMA)

In D.12-11-051, the Commission approved the continued use of the existing MRTUMA for the 7

future recovery of the incremental MRTU-related revenue requirements in rates consistent with 8

169 Advice Letter 2826-E was approved by the Commission’s Energy Division with an effective date of December 19, 2012.

L ineN o . D e sc rip tio n ($ 0 0 0 )

1. B e g in n in g B a la n c e 1 / - 2 . P rio r Ye a r A d ju s t m e n t s :3 . 2009-2011 R a te o f R e tu rn A d ju s t m e n t (22) 4 . B e g in n in g A d ju s t e d B a la n c e 1 / (22)

5 . In c re m e n t a l O & M Exp e n s e s6 . In fo rm a t io n T e c h n o lo g y S o ftw a re C o s t s (IT S C ) 2 ,526 7 . Le s s : F ER C Ju ris d ic t io n a l A m o u n t s (108)

8 . IT S C (C P U C Ju ris d ic t io n a l) 2 ,418

9 . C a p it a l R e v e n u e R e q u ire m e n t s

10. C a p it a l R e v e n u e R e q u ire m e n t s 4 ,834

11 . Le s s : F ER C Ju ris d ic t io n a l A m t s . (208) 12 . C a p it a l R e v e n u e R e q u ire m e n t s (C P U C Ju ris d ic t io n a l) 4 ,626

13 . (O v e r)/ U n d e r C o lle c t io n (Lin e 8 + Lin e 12) 7 ,044

14 . In t e re s t 4

15 . En d in g B a la n c e (Lin e 4 + Lin e 13 + Lin e 15) 7 ,027

1 / F o r p ur p o se s o f t h is t e st im o n y , t h e B e gin n in g B a la n c e do e s n o t in c lude $ 1 7 .1 4 6 m illio n c ur r e n t ly un de r C o m m issio nr e v ie w in t h e M R T U M A A .1 2 - 0 1 - 0 1 4 a n d $ 2 0 .3 4 5 m illio n c ur r e n t ly un de r C o m m issio n r e v ie w in t h e E R R A A .1 2 - 0 4 - 0 0 1 .

193

Resolution E-4087. SCE’s O&M and capital requests that are associated with the implementation of 1

MRTU will continue to be recorded in the MRTUMA. Per D.12-0-11-051, the 2009 MRTU-related 2

recorded O&M and capital included in the 2012 GRC revenue requirement is excluded from the 3

MRTUMA. 4

As shown on Line 8 in the table above, SCE recorded $2.418 million of incremental CPUC-5

jurisdictional IT maintenance costs in the MRTUMA during 2012. The total capital-related revenue 6

requirement (i.e., depreciation, return on rate base, and taxes) recorded in the MRTUMA as shown on 7

Line 12 of Table XIV-60 was $4.626 million associated with direct capital expenditures of $1.02 8

million, plus overhead of $0.079 million associated primarily with Allowance for Funds Used During 9

Construction.170 Specifically, SCE incurred $3.152 million in depreciation, $0.161 million for taxes, 10

and $1.521 million of return on rate base. In addition, a capital rate of return true-up for the years 2009-11

2011 resulted in a credit adjustment recorded in the MRTUMA of $0.022 million as shown on Line 3 of 12

Table XIV-60. 13

E. Conclusion 14

SCE requests that the Commission find the costs recorded in the MRTUMA during this Record 15

Period in the amount of $7.027 million, were incurred to implement the MRTU and MAP initiatives and 16

are reasonable and recoverable. Upon a Commission finding that these costs are recoverable, SCE will 17

transfer $7.027 million, with accrued interest through the date of transfer, from the MRTUMA to the 18

generation sub-account of the Base Rate Revenue Requirement Balancing Account (BRRBA) for 19

recovery. 20

170 Further details for the AFUDC amount can be found in SCE’s supporting workpapers.

194

XV. 1

MOHAVE BALANCING ACCOUNT 2

A. Introduction 3


MBA; (2) present the entries recorded in the MBA during the 2012 Record Period for Commission 5

review; and (3) demonstrate that the entries recorded in the MBA are appropriated, correctly stated, and 6

in compliance with prior Commission decisions. 7

B. Background and Ratemaking 8

This chapter supports the entries recorded in the MBA, which was established pursuant to OP 8 9

of SCE’s 2006 GRC decision (D.06-05-016). In its scoping memo in SCE’s April 2007 ERRA Review 10

Proceeding, A.07-04-001, the Commission stated that it would not review the entries recorded in the 11

MBA until SCE first addressed the permanent status of the Mohave plant, as required by OP 9 of D.06-12

05-016. In June 2009, SCE and the co-owners decided to cease efforts to sell Mohave, and to proceed 13

immediately to decommission Mohave and remove the generating station equipment from the site.171 14

Having determined the permanent status of Mohave, and pursuant to Preliminary Statement, Part NN, 15

MBA, SCE included the 2006 through 2010 operation of the MBA for Commission review in its April 16

2011 ERRA Review application, A.11-04-001. The 2011 operation of the MBA is included in the April 17

2012 ERRA Review application, A.12-04-001.172 As such, the Commission should find that this ERRA 18

Review proceeding is an appropriate forum in which to review SCE’s recorded entries in the MBA for 19

the 2012 Record Period. 20

Specifically, SCE requests a Commission finding that for the period January 1, 2012 through 21

December 31, 2012, the capital revenue requirement (i.e., depreciation, property and income taxes)173 in 22

171 SCE first informed the Commission of these developments in its June 10, 2009 Mohave Monthly Status Report, in

compliance with OP 4 of D.04-12-016. 172 The balances for the 2006 through 2010 and 2011Record Periods presented in SCE’s ERRA Review applications, A.11-

04-001 and A.12-04-001, are still pending before the Commission. 173 Pursuant to OP 37 of D.12-11-051, SCE shall not earn a rate of return on rate base.

195

the amount of $9.368 million, and operating expenses (including worker protection expenses) in the 1

amount of $0.276 million, recorded in the MBA during the Record Period were properly recorded and 2

consistent with D.06-05-016,174 D.09-03-025,175 and D.12-11-051.176 3

C. Operation of the MBA 4

The purpose of this section is to set forth the operation of the MBA for the Record Period for 5

Commission review. In D.06-05-016, the Commission authorized SCE to establish the two-way MBA 6

to recover certain costs associated with the Mohave Generating Facility shutdown. In D.09-03-025 the 7

Commission affirmed the authorization to continue to use the MBA during the 2009 through 2011 8

period. In D.12-11-051, the Commission affirmed the authorization to continue to use the MBA during 9

the 2012 through 2014 period. Consistent with Preliminary Statement, Part NN, MBA, SCE records 10

each month the difference between: (1) recorded capital-related revenue requirement;177 (2) operating 11

expenses and worker protection expenses associated with Mohave; and (3) the authorized Mohave 12

revenue requirement adopted in D.06-05-016, D.09-03-025 and D.12-11-051. 13

Pursuant to the terms of the MBA, any over- or under-collection in the account is transferred on 14

an annual basis to the BRRBA to be returned to or recovered from SCE’s customers. As shown on Line 15

21 in Table below, during the Record Period178 SCE transferred a total under-collected amount of 16

$6.015 million to the generation sub-account of the BRRBA to be recovered from customers. Table 17

XV-61 below sets forth a summary of the entries recorded in the MBA during the Record Period. 18

174 SCE filed Advice 2003-E on May 22, 2006, implementing the 2006 GRC adopted revenue requirements and ratemaking

mechanisms in accordance with D.06-05-016. 175 SCE filed Advice 2336-E on March 30, 2009, implementing the 2009 GRC adopted revenue requirements and

ratemaking mechanisms in accordance with D.09-03-025. 176 SCE filed Advice 2826-E on December 19, 2012, implementing the 2012 GRC adopted revenue requirements and

ratemaking mechanisms in accordance with D.12-11-051. 177 The capital-related revenue requirements include book depreciation, authorized return on recorded rate base, and

applicable taxes. In 2012, SCE did not earn a rate of return on rate base for Mohave. 178 The accounting entry transferring the 2012 MBA ending balance to the BRRBA generation sub-account recorded as a

beginning-period adjustment in January 2013. Details are included in workpapers.

1

2

3

4

D. M

D

associate

decommi

Mohave Cap

During the Re

ed with the re

issioning-rel

Mo

pital-Related

ecord Period

ecorded net

lated expens

ohave Bala

d Revenue R

d, SCE recor

plant investm

ses, as incurr

196

Table XV-ancing Acco

Requiremen

rded on a mo

ment as of D

red. As show

-61 ount 2012

nt

onthly basis

December 31

wn on Line 9

the capital-r

1, 2005 and r

9 of Table X

related expen

recorded

XV-61, the am

nses

mount of

197

capital-related revenue requirement totaled $9.368 million. The capital-related revenue requirement 1

includes depreciation expense based on the adopted depreciation rates, and associated taxes (income and 2

property taxes). 3

E. Operating Expenses 4

1. O&M Costs 5

a) Background 6

The following is a condensed timeline covering the time period from when the facility was 7

removed from service on December 31, 2005 through the end of 2012: 8

� On December 31, 2005 both generating units performed a safe and orderly shutdown, and 9

all equipment was prepared for an extended lay-up. 10

� In the latter half of 2006 Mohave was transitioned into Temporary Shutdown status and 11

plant employees undertook actions to prepare the facility for sale or decommissioning. 12

Critical permits such as the Title V Air permit and the Colorado River Water contract 13

were maintained. 14

� On October 1, 2007 the plant was transitioned into Permanent Shutdown status. SCE and 15

the other co-owners discontinued certain equipment preservation work and initiated early 16

work activity in preparation for possible decommissioning of the facility. 17

� From October 2007 through April 2011 some equipment preservation activity continued 18

and certain plant systems such as the potable water system, sewage treatment system, and 19

the river pump house, were operated and maintained due to the continued need for site 20

personnel to provide 24 hours/day monitoring and control of the 500kV switchyard. 21

Efforts to sell the facility continued until the decision to decommission the facility was 22

made by the owners in June, 2009. 23

� On May 10, 2011 Mohave Generating Station was electrically separated from the 24

switchyard and made available for decommissioning. By July 2011, remaining staff was 25

reduced to five fulltime SCE employees, primarily associated with the decommissioning 26

198

project. By the end of 2011, four full time SCE employees remained at the site. The 1

Colorado River contract was terminated in August 2011. 2

b) 2012 Record Period Expenses 3

During 2012, the plant staff primarily focused on assuring that the plant decommissioning 4

activities were conducted in a safe and environmentally-compliant manner. O&M costs incurred were 5

associated with administration activities and site maintenance for perimeter fence repairs, trash removal, 6

and ongoing compliance activities such as maintaining and sampling groundwater monitoring wells. 7

Administrative activities consisted of employee and contractor support, budget tracking, and meetings 8

with the co-owners. At the end of the Record Period, there were four remaining full-time employees 9

working under Temporary Work Assignments179 with a planned end date of April 2013. SCE expects 10

O&M work to continue at the site both through the end of decommissioning and after decommissioning 11

is completed.180 12

SCE’s share of these plant O&M expenses during the Record Period totaled $0.276 million as 13

shown on Line 15 of Table XV-61. SCE requests the Commission find these expenses reasonable and in 14

compliance with D.06-05-016, D.09-03-025, and D.12-11-051. 15

2. A&G, Payroll Taxes, and A&G Participant Credits 16

Consistent with the terms of the MBA, each month SCE records Mohave-related A&G expenses 17

(property and workers compensation insurance and benefits) and payroll taxes.181 The A&G expenses 18

and payroll taxes totaled $0.048 million during the Record Period, as presented on Line 12 of Table XV-19

179 A Temporary Work Assignment, or TWA, is one that defines a work assignment for a finite period of time, at the end of

which the employee must either obtain another position within SCE or be terminated. 180 Certain O&M activities, including but not limited to plant security, grounds maintenance, prevention of soil erosion, and

post closure environmental monitoring of the landfill, will continue post-decommissioning. 181 Mohave insurance expenses are separately identified in SCE’s recorded expenses. Recorded Mohave-related benefits

and payroll taxes are calculated in conformity with the authorized benefit amount per labor dollar and the total monthly recorded O&M labor amount. Since 2009, medical, dental, and vision benefits were removed from the Mohave benefit totals since the amounts are recovered through the Medical Programs Balancing Account. Mohave payroll taxes are calculated based on the monthly recorded O&M labor amount and the payroll tax rate.

199

61, above. In addition, SCE recorded participant credits182 related to the Mohave co-owners’ share of 1

A&G costs to operate the facility and the co-owners’ share of benefits for those A&G costs. The 2

participant credits totaled $0.058 million, as presented on Line 13 of Table XV-61 above. 3

3. Worker Protection Expenses 4

SCE records it share of worker protection benefits for expenses related to Mohave employees. In 5

2012, SCE incurred charges from AON Hewitt consulting firm for additional calculations and assistance 6

with the Retirement Plan and PBOP trust contributions that were made in January, 2012 for Mohave.183 7

F. Plant Decommissioning Status 8

As described in the ERRA 2011 Review of Operations, A.12-04-001, SCE-2,184 SCE mobilized 9

the site and began decommissioning activities in mid-2009 through 2011. It was noted in the 2011 10

Record Period that new switchyard facilities were necessary to allow the generating station to be 11

electrically separated for demolition of the plant. Schedule delays were experienced during the 12

construction of new switchyard facilities due to the presence of asbestos materials. At that time, most 13

remaining decommissioning work was forecasted to be completed by mid-2012. From project inception 14

through December 31, 2012, SCE recorded approximately $40.024 million of expenditures for 15

decommissioning and switchyard separation (SCE share, work order level). This includes credits 16

generated from the sale of scrap material. 17

During the 2012 Record Period, several events further impacted the schedule. The scheduled 18

date for implosion of the steam generator structures and turbine generator concrete pedestals was first 19

delayed due to the sale of the main steam turbines, generators and associated equipment. The sale 20

occurred in late January and included time for the buyer of this equipment to dismantle it and remove it 21

182 A&G participant credits are calculated based on the annual A&G labor rate, A&G non-labor rate, payroll tax rate, and on

the total monthly recorded O&M labor and non-labor amounts. 183 An error for recorded worker protection expenses was identified due to incorrect billing from AON Hewitt. The correct

charges total $0.003 million (SCE share) and a credit for the difference will be reimbursed to SCE in 2013. The reimbursement will be included in the 2014 ERRA Review filing for the 2013 Record Period.

184 Chapter XVII, Part G, pp. 227-229.

200

from the site. Dismantling was to be completed by mid-April so that the structure implosions could 1

proceed in late April. However, in late March, an active Great Horned Owl’s nest was discovered on the 2

Unit 1 boiler structure, despite best efforts to prevent nesting activity from occurring. This further 3

delayed the structure implosions until the fledgling chicks could be safely removed from the area. The 4

structure implosions occurred in early June, and the implosion of the turbine/generator pedestals 5

occurred in early September. 6

Major decommissioning activities completed during the Record Period included closure of all 7

nine on-site evaporation ponds. The demolition of remaining site buildings was completed. The 8

remaining portions of the station circulating water system were removed, including the cooling towers, 9

their foundations and the circulating water canal and pump intake structure that conveyed the cooled 10

water back to the generating units. All remaining water makeup and treatment systems, such as the 11

primary water softener and the brine concentrator, were removed. As noted above, the boiler structures 12

were imploded, and approximately 23,000 tons of structural steel and pressure components were 13

processed, sized, and sold for recycling. The formal closure of the permitted ash landfill began after 14

receipt of a closure amendment that was approved by the Southern Nevada Health District in January 15

2012. The permit required extensive earthwork for drainage control, and required a significant drainage 16

control system to be constructed for storm water run-off. Landfill closure was substantially completed 17

by the end of 2012, with the exception of one active cell that was kept open for placement of remaining 18

concrete and asphalt material from other areas of the plant. Final grading has not been completed in the 19

area where the boiler structures and turbine generator pedestals were located. The soil remediation 20

activities in the area of the generating station transformer yard were completed in March 2013. It is 21

currently forecast that the decommissioning contractor demobilization, from the site, will be completed 22

by mid-April 2013. 23

G. Conclusion 24

In conclusion, SCE requests the Commission to find that: (1) the amounts recorded in the MBA 25

for the Record Period are reasonable and consistent with Commission decisions, D.06-05-016, D.09-03-26

025, and D.12-11-051. Expenditures at Mohave that continue after the Record Period relating to the 27

201

ongoing management, decommissioning, and the final disposition of the site will be reviewed in future 1

ERRA proceedings. 2

202

XVI. 1

AUDITS 2

This chapter describes the Audit Services Department’s (ASD) auditing process and controls and 3

specific reviews related to utility-owned generation (UOG) management and outage mitigation. 4

The ASD of SCE selects its audits on a risk-based methodology. Every project adheres to our 5

Work Practice Standards. A typical audit consists of the following: 6

� Preliminary Survey 7 � Engagement Level Risk Assessment 8 � Engagement Plan 9 � Engagement Announcement 10 � Entrance Conference 11 � Work Program 12 � Fieldwork Sections 13 � Observations 14 � Exit Conference 15 � Evaluation of Audit Observation Form 16 � Engagement Report 17 � Evaluation 18 � Engagement Checklist (Optional) 19 � Track Open Observations 20

For SCE’s UOG management and outages during the Record Period, Audits Services focused a 21

majority of the audits on San Onofre Nuclear Generating Station (SONGS). Below is a recap of the 22

SONGS and other UOG audits completed in 2012: 23

A. SONGS Inventory Warehouse Processes and Practices (Store Location 0907 and newly 24

created Store 0060) (Y11-52013) 25

On April 23, 2012, ASD issued an audit report pertaining to its review of the inventory 26

management processes over the storage, issuance, movement, and transfers of materials between two 27

warehouses located on-site within the Protected Area of the plant. As part of this review, ASD 28

conducted physical inventory counts at both warehouses to evaluate the accuracy of inventory and 29

adequacy of management processes and controls. 30

31

203

1

2

B. San Onofre Nuclear Generating Station (SONGS) – Environmental Preliminary 3

Assessment (Y11-52015) 4

On March 12, 2012, ASD issued an audit report pertaining to its preliminary assessment of the 5

Environmental Programs implemented at the SONGS. The objective of the assessment was to 6

determine whether SONGS management appropriately identified and evaluated environmental related 7

risks and controlled them in an effective manner. In addition, the assessment was used to identify areas 8

for potential future audits requiring detailed testing. 9

10

11

12

C. SONGS’ Contingent Worker Timekeeping Process Review (Y12-11102) 13

On October 12, 2012, Audit Services issued an audit report pertaining to its review of the 14

SONGS’ timekeeping process for contingent workers. The objective was to review the adequacy of 15

processing payroll for non-represented contingent workers. 16

17

18

19

D. SONGS Workplace Safety Inspection Process (Y12-52003) 20

On September 27, 2012, ASD issued an audit report pertaining to its review of the Workplace 21

Safety Inspection Process implemented at SONGS. The primary objective of the review was to evaluate 22

the effectiveness of the program and the work practices used to conduct workplace safety inspections. 23

24

25

26

27

204

1

2

E. SONGS NRC Cyber Security Project Review (Y12-74004) 3

On October 3, 2012, ASD issued an audit report pertaining to its review of the SONGS Nuclear 4

Regulatory Commission (NRC) Cyber Security project. The objective of the review was to provide an 5

independent assessment of the SONGS project established to fulfill the requirements of the SONGS 6

License Amendments (Approval of Cyber Security Plan). 7

8

9

In addition to the above projects, ASD also conducted two joint assessments with the Nuclear 10

Oversight Division pertaining to Procurement and Material Control. 11

F. Catalina Plant - (Y11-53003) 12

For SCE’s Catalina operations, ASD conducted an audit focused on Maintenance & Inspections 13

(M&I) processes of critical generation equipment and related components, as well as distribution assets. 14

ASD also evaluated station management’s focus on fraud. In addition, ASD assessed compliance with 15

selected EH&S regulatory, corporate and site policies and procedures related to air quality, spill 16

prevention and control, water quality, fire prevention, walking/working surfaces, lockout/tagout, use of 17

atmospheric monitors, construction safety, and the gas pipeline safety program. 18

G. Outage Management - (Y11-76010) 19

In regards to outage management, ASD completed a technical review of the Outage Management 20

System (OMS). The objective of this audit was to assess the effectiveness of the controls in place to 21

mitigate risk to the operations and reporting goals of grid operations and call center. 22

23

24

Other audits commenced in 2012 as part of ASD Audit Plan Year, that pertained to UOG 25

management and outages include the following: 26

205

H. SONGS Aboveground Storage Tanks (Y12-52002) 1

The primary objective of the review was to evaluate the effectiveness of the program and work 2

practices. In addition, the adequacy of the controls and adherence to program requirements were 3

assessed. The scope of the audit involved documentation reviews, a physical walk-down and inspection 4

of the tanks, and discussions with the SONGS environmental and subject matter experts. SONGS 5

currently has a comprehensive Aboveground Storage Tanks (AST) and Title 22 program in place that 6

meets the procedural requirements specified in the program. In addition, no regulatory agency reporting 7

of non-compliance related to the program was observed. 8

I. Operational & Environmental, Health and Safety Assessment - Mountainview (Y12-52011) 9

The primary objective of this assessment was to determine if key maintenance, inspection, and 10

EH&S activities and programs, including management controls and documentation at Mountainview are 11

operating effectively. 12

13

14

15

16

17

J. Outage Management Process – Planned Outages (Y12-58009) 18

ASD commenced this audit in October 2012. The objective of the audit engagement is to assess 19

the effectiveness of the planned outage communication process in notifying the customer and validating 20

service guarantees. 21

PUBL IC VERSION - Southern California Edison...J. Aldri T. Fron K. Bleb P. Ott M. Ben G. Hen J. Rumb...

Documents

Transcript of PUBL IC VERSION - Southern California Edison...J. Aldri T. Fron K. Bleb P. Ott M. Ben G. Hen J. Rumb...