PEAKERS COST RECOVERY TESTIMONY...12 ratemaking request in Advice 2031-E (effective November 9,...

Application No.: A-07-12 Exhibit No.: SCE-1 Witnesses: A. Kurpakus

P. Phelan D. Snow

(U 338-E)

PEAKERS COST RECOVERY TESTIMONY

Before the

Public Utilities Commission of the State of California

Rosemead, California

December 31, 2007

Testimony Table Of Contents

Section Page Witness

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I. INTRODUCTION .............................................................................................1 D. Snow

II. BACKGROUND ...............................................................................................2

A. History of the SCE Peaker Projects 2 P. Phelan

B. Peaker Cost Recovery Pursuant to the ACR 4 D. Snow

1. Advice 2031-E and Resolution E-4031 5

2. SCE’s Test Year 2009 General Rate Case (2009 GRC) 5

C. Overview of the SCE Peakers 6

1. General Overview of an SCE Peaker Unit 6 P. Phelan

2. SCE’s Peaker Division 9 A. Kurpakus

III. OPERATION OF THE PGMA (AUGUST 2007 THROUGH NOVEMBER 2007).........................................................................................12 D. Snow

IV. OPERATION AND MAINTENANCE EXPENSES ......................................14 A. Kurpakus

A. Labor Costs 15

B. Non-Labor Costs 16

1. Major Maintenance 16

2. Routine Annual Maintenance 16

3. Water, Water Treatment, Ammonia, and Other Supplies and Consumables16

4. Miscellaneous Non-Labor Costs 17

C. Recorded Costs by FERC Account 19

1. FERC Account 546 – Operation Supervision and Engineering 19

a) Description of Account 19

b) Expenses Incurred for Account 546 19

2. FERC Account 548 –- Generation Expenses 20


Testimony Table Of Contents (Continued)


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3. FERC Account 549 – Miscellaneous Other Power Generation Expenses 20



4. FERC Account 550 – Rents 21



5. FERC Account 551 – Maintenance Supervision and Engineering 21



6. FERC Account 553 – Maintenance of Generating and Electric Plant 22



7. FERC Account 554 – Maintenance of Miscellaneous Other Power

Generation Plant 22



8. FERC Account 562 – Operations of Station Transmission Equipment 23



9. FERC Account 570 – Station Transmission Equipment 23



V. PEAKER ACQUISITION AND INSTALLATION COSTS..........................25 P. Phelan

A. Overview 25

Testimony Table Of Contents (Continued)


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1. Committed Costs Not Yet Recorded 25

2. Forecast of Remaining Work to be Performed at Peaker Sites Currently

In Service 26

a. Barre Peaker 26

b. Center Peaker 26

c. Mira Loma Peaker 27

3. Total 27

B. Cost of Materials 28

1. Cost of Major Peaker Components 28

2. Remaining Balance of Plant Equipment Not Provided by General Electric30

C. Cost of Gas Pipeline Installation 31

D. Cost of Electrical Interconnection 32

E. Costs of Engineering, Construction and Home Office 32

VI. COST RECOVERY FROM ALL BENEFITING CUSTOMERS ..................34 D. Snow

A. Background 34

B. Cost Recovery Proposal 35

C. Modification to the New Generation System Balancing Account 35

VII. FUTURE REVIEW OF PGMA COSTS .........................................................37 D. Snow

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I. 1

INTRODUCTION 2

The purpose of this testimony is to demonstrate the reasonableness of costs incurred by Southern 3

California Edison Company (SCE) to acquire and install four peaker generation units, as directed by the 4

California Public Utilities Commission (Commission) in Ordering Paragraph 6 of Resolution E-4031 5

(issued November 9, 2006). 6

Specifically, this testimony: 7

1. Explains and supports the entries made to the Peakers Generation Memorandum Account 8

(PGMA) for the period August 2007 through November 2007; 9

2. Demonstrates that the Commission should find reasonable $1.279 million of Operating 10

and Maintenance (O&M) expenses for the period August 2007 through November 2007; 11

3. Demonstrates that the Commission should find reasonable the direct capital expenditures 12

associated with the four operational peaker units, which currently stand at $238 million, 13

and are forecast to total approximately $262 million when all initial construction on the 14

four units is completed in 2008; 15

4. Explains that the Commission should grant authority to recover the revenue requirement 16

associated with the peaker generation units from all SCE “benefiting customers” (as 17

defined herein); and 18

5. Requests that the Commission review costs recorded in the PGMA from December 2007 19

through December 2008 in SCE’s April 2009 Energy Resource Recovery Account 20

(ERRA) Reasonableness of Operations proceeding.21

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II. 1

BACKGROUND 2

A. History of the SCE Peaker Projects 3

On August 15, 2006, in response to the extraordinary heat storm that affected California through 4

much of July 2006, and the far higher than forecast peak electricity demands experienced during that 5

time, Commission President Michael R. Peevey issued the Assigned Commissioner’s Ruling Addressing 6

Electric Reliability Needs in Southern California for Summer 2007 (ACR). With respect to SCE, the 7

ACR directed SCE to pursue three different steps to help avoid the possibility of generation capacity 8

shortages and transmission and distribution grid instability in the summer of 2007 and thereafter: (1) to 9

pursue additional demand response through expansion of SCE’s air conditioning cycling program; (2) to 10

modify SCE’s then-existing Request For Offers from power producers to specifically seek offers for 11

dispatchable, black-start capable generation that could be brought on-line by summer 2007; and (3) to 12

pursue the development of up to five SCE-owned, dispatchable and black-start capable generating units, 13

of up to 250 megawatts (MW) total generating capacity, that could be brought online by Summer 2007. 14

The ACR also specified that the SCE-developed units should “bring collateral benefits to SCE’s 15

transmission and distribution system as well as the CAISO grid.”1 16

To meet the one-year completion schedule set out in the ACR, SCE immediately embarked on 17

several concurrent, parallel paths to develop the SCE peakers, including: identifying and selecting 18

optimal sites for the peakers, and then initiating the required permitting processes; designing and 19

engineering the peaker plants; securing the necessary gas pipeline and electrical interconnections; and 20

acquiring the peaker turbine units and other plant equipment. Consistent with the ACR, SCE pursued 21

development of five SCE peaker units, of approximately 45 MW net generating capacity each. SCE has 22

reported monthly to the Commission on the status of the five projects. 23

24

1 ACR at p. 6.

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Four of the peaker projects received all permitting required for onsite construction to begin, 1

including completion of the California Environmental Quality Act (CEQA) environmental review 2

process, by the second quarter of 2007, and onsite construction began immediately thereafter at those 3

project sites. Those four peakers were all installed went into operation and were available for 4

emergency use by August 1, 2007 (although certain post-startup work continues at some sites, as 5

described in this testimony). The remaining project, proposed to be sited adjacent to the existing 6

Mandalay Generating Station and switchyards in Oxnard, California, has not completed its permitting 7

process, as discussed below. The four peakers that are now installed and operational are: (1) Barre 8

Peaker, located at SCE’s Barre Substation in Stanton, CA; (2) Center Peaker, located at SCE’s Center 9

Substation in Norwalk, CA; (3) Grapeland Peaker, located near SCE’s Etiwanda Substation in Rancho 10

Cucamonga, CA; and (4) Mira Loma Peaker, located at SCE’s Mira Loma Substation in Ontario, CA. 11

The locations of all five peaker projects are shown in the map at Figure II-1 below. 12

Figure II-1 Locations of Peaker Projects

With respect to the fifth peaker project, proposed for Oxnard, California, the city denied SCE’s 13

application for a Coastal Development Permit, which is required before construction of the project could 14

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begin. Accordingly, no onsite construction has taken place on that project. It should be noted that the 1

peaker unit itself and related equipment have been largely fabricated and are being held in storage in 2

anticipation of the ultimate completion of the project. SCE believes both that the permit denial by the 3

City of Oxnard was without merit, and because of various transmission constraints affecting the Ventura 4

County-Santa Barbara County area, SCE believes that the proposed site remains an optional and very 5

important location for the black-start and quick-start capable peaker unit available for use at the site. 6

Therefore, SCE continues to pursue development of that unit, and has appealed the permit denial by the 7

City of Oxnard to the California Coastal Commission. In this Application, therefore, SCE also requests 8

express Commission recognition that SCE may continue tracking all costs of acquiring and installing the 9

fifth peaker unit in SCE’s existing work order for that unit, consistent with the procedure set out in 10

Resolution E-4031, and that SCE may file a separate application after that fifth peaker is installed (or its 11

final disposition is otherwise determined) to demonstrate the reasonableness of, and to address 12

ratemaking treatment of, those costs. 13

All four of the installed peakers have been needed and dispatched by the CAISO at different 14

times since they became available in August 2007, primarily during the heat wave that hit southern 15

California during the last week of August 2007, and during the late-October 2007 period of severe Santa 16

Ana winds and widespread brush fires that affected transmission and distribution availability throughout 17

much of southern California. 18

B. Peaker Cost Recovery Pursuant to the ACR 19

As discussed above, the ACR directed SCE to pursue the development of up to five SCE-owned, 20

black-start capable, dispatchable peaker generation units, of up to 250 MW total generating capacity for 21

summer 2007 operations. The ACR also: (1) invited SCE to file an advice letter to establish a 22

memorandum account to record the acquisition and installation costs of the peaker generation units, 23

because it did not appear possible to determine ratemaking treatment for the costs in advance, given the 24

one-year schedule; and (2) recognized that, because of the urgent need for generating capacity during the 25

summer of 2007 and the steps being taken in the ACR, SCE could propose in its subsequent rate 26

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application (and the Commission could consider) different ratemaking treatment than the Commission 1

had established for typical utility-owned generation in Decision (D.) 06-07-029. 2

1. Advice 2031-E and Resolution E-4031 3

Consistent with the ACR, SCE filed Advice 2031-E on August 24, 2006, requesting 4

Commission authority to: (1) establish the PGMA; and (2) revise the Generation Sub-account of the 5

Base Revenue Requirement Balancing Account (BRRBA) to provide for monthly transfers of the peaker 6

generation units’ revenue requirements that are recorded in the PGMA to the Generation Sub-account of 7

the BRRBA. As discussed in more detail below, SCE will only record the revenue requirements 8

associated with the operating peaker units in the PGMA until the associated revenue requirements are 9

included in SCE’s General Rate Case (GRC) revenue requirement. 10

The Commission, in Resolution E-4031, approved (with modifications) SCE’s 11

ratemaking request in Advice 2031-E (effective November 9, 2006). In addition, in Ordering Paragraph 12

6 of Resolution E-4031, the Commission directed SCE to file an application no later than December 31, 13

2007 (the instant Application) to “demonstrate the reasonableness of the accrued acquisition and 14

installation costs tracked in a ‘work order’ and the associated revenue requirement recorded in the 15

PGMA.” 16

2. SCE’s Test Year 2009 General Rate Case (2009 GRC) 17

On November 19, 2007, SCE filed its 2009 GRC (Application (A.) 07-11-011) that 18

includes a forecast revenue requirement associated with five peaker generation units to become effective 19

on January 1, 2009. SCE anticipates that the fifth peaker generation unit will be completed and ready 20

for commercial operation in 2008. If the Commission finds in this instant application that recorded costs 21

associated with the four operational peaker generation units were reasonably incurred, then no further 22

ratemaking action is necessary with respect to these four peakers. If, however, the Commission finds in 23

this instant application that some portion of recorded costs associated with the four operational peaker 24

generation units should not be recovered through the PGMA or the BRRBA, then SCE will make 25

appropriate ratemaking adjustments in both the PGMA and the BRRBA. In addition, SCE will make 26

appropriate adjustments to its forecast 2009, 2010, and 2011 revenue requirements in its 2009 GRC. 27

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As mentioned, subsequent to the commercial operating date of the fifth peaker generation 1

unit, SCE will file a separate application with the Commission showing the reasonableness of costs 2

incurred by SCE for that unit. In the same manner described above for the four currently operational 3

peaker generation units, SCE will make appropriate ratemaking adjustments for any costs found not 4

recoverable as needed, to the PGMA and BRRBA, as well as in SCE’s 2009 GRC proceeding.2 5

C. Overview of the SCE Peakers 6

1. General Overview of an SCE Peaker Unit 7

Each SCE peaker consists of one General Electric (GE) LM6000 SPRINT™ (SPRay 8

INTercooling)3 gas turbine generator, together with associated auxiliary equipment, including selective 9

catalytic reduction (SCR) emission control equipment for nitrogen oxide (NOx). The turbine is 10

permitted to fire only natural gas. The turbine is capable of stable operation at 60 to 100 percent load 11

while meeting hourly emission limits. 12

Photographs of each of the four completed SCE peakers are included as EXHIBIT 1 to 13

this testimony. Figure II-2 below is a schematic illustration of an SCE peaker highlighting certain major 14

equipment: 15

• LM6000 gas turbine generator; 16 • Inlet air filter housing; 17 • Provisions for a mobile “demineralizer” water treatment system, which provides 18

treated water to the above-listed equipment; 19 • Auxiliary transformers; 20 • Storage for aqueous ammonia (19% solution) for emission controls; 21 • SCR/CO and NOx catalyst; 22 • Natural gas compressors; 23 • Black-start generator; and 24 • Acoustical enclosures designed for outdoor service. 25

26

2 SCE’s 2009 GRC forecast of peaker capital expenditures will be adjusted for capital expenditures not found recoverable;

however, SCE’s 2009 GRC O&M peaker forecast will not be adjusted for recorded peaker O&M expenses found not recoverable since SCE’s 2009 GRC peaker O&M forecast is based on expected 2009 O&M expenses.

3 General Electric's SPRINT designation refers to the fact that these plants include equipment that allows water to be injected into the combustion turbine. These injections control NOx emissions, and increase the turbine's power output.

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Figure II-2 Typical Peaker Design

The turbine consumes natural gas, air, and water, each of which is conditioned prior to 1

use: 2

• The local gas pipeline provides natural gas, and an 800 hp electric fuel gas 3

compressor then compresses it to sufficient pressure for the combustion turbine. 4

• The local water utility provides water to the site. A portable demineralizer, 5

consisting of water softening followed by ion exchange, treats the water to a very 6

high purity level. A storage tank holds the treated water prior to use. NOx 7

emissions control requires treated water to be injected into the turbine. This water 8

injection also increases the power output of the turbine. Inlet air conditioning also 9

uses treated water. 10

• A self-cleaning filter removes suspended matter in the ambient air prior to use to 11

minimize the damage such matter can cause to the turbine. When the ambient 12

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temperature is high, an injection of a fine water mist cools the inlet air. This 1

boosts the unit’s power output and fuel efficiency. 2

Exhaust gases from the combustion turbine are routed to an 80-foot tall exhaust stack. 3

Additional water injection into the turbine, the SCR system for NOx control, and an additional layer of 4

catalyst in the exhaust gas ducting for the control of carbon monoxide (CO), rigorously control air 5

emissions. The SCR system reduces NOx emissions down to 2.5 parts per million (PPM). The SCR 6

system uses aqueous ammonia from a 10,500 gallon storage tank as the reagent for the SCR. A separate 7

oxidation catalyst strips out CO emissions present in the exhaust gas. A Continuous Emissions 8

Monitoring System (CEMS) measures and reports on the effectiveness of this air pollution control 9

equipment to SCE and appropriate agencies. 10

Each peaker has a 645 kW auxiliary electric generator driven by a natural gas-fired 11

reciprocating engine. These auxiliary generators provide each peaker with black-start capability by 12

providing the initial power to operate the auxiliary equipment required for start-up of the peaker. 13

Peakers support the bulk power grid by starting and ramping to full load rapidly and 14

repeatedly, including starting and stopping more than once in a day if needed and appropriate. These 15

peakers have a relatively low incremental cost for each start-up, and each peaker can reach full load in 16

10 minutes after start-up. 17

It is expected that the peakers will primarily operate during summer weekdays, when load 18

on the grid peaks in the afternoons, and particularly during extreme hot weather. However, the peakers 19

are available at any time to meet unexpected demand or other emergencies. The peakers have already 20

operated on a number of occasions since the initiation of operations in August 2007, to serve customer 21

load and to assist in meeting bulk power grid demands and emergencies. Most notably, the peakers 22

were dispatched a number of times during the late-August heat storm and during the late-October period 23

of severe Santa Ana winds and brush fires. Including commissioning testing, through November 2007, 24

each of the four peakers has logged approximately 70 startups. 25

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2. SCE’s Peaker Division 1

SCE has centralized the technical, administrative, and operational oversight of the 2

peakers. A peaker control center will start, stop, and monitor the peakers. The existing Mountainview 3

Generating Station (Mountainview) is the location of the primary peaker control center. The peaker 4

control center consists of a dedicated control room and communications facilities, located adjacent to the 5

existing Mountainview Units 3 & 4 control room. SCE manages the peaker operations functions from 6

this facility. 7

SCE’s existing Shop Services and Instrument Department (SSID) complex in 8

Westminster (Orange County) contains a secondary peaker control center. Because the locations of the 9

peakers are spread over such a large geographic region, this secondary control center provides 10

redundancy if communications between the peakers and the primary control center at Mountainview are 11

lost. This loss of communications could result from a catastrophic natural event such as an earthquake, 12

loss of communications lines resulting from human-caused events, or a major power grid disturbance. 13

Having this back-up facility, which is also located near two of the peakers, will help enable quick 14

restoration of the grid should black-start of the units be required. 15

SSID is also the headquarters location for the peaker maintenance and administrative 16

staff, and houses the Peaker Division's spare parts and consumables warehouse, and maintenance shop 17

facilities. The secondary peaker control center at this location allows technicians and management 18

personnel at this location to remotely monitor peaker start-ups and equipment. This additional level of 19

oversight helps assure high levels of peaker reliability. 20

Figure II-3 is an organization chart for the Peaker Division. 21

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Figure II-3 Peakers Organization Chart

A Peaker Manager leads the Peaker Division. An Operations Manager assists the Peaker 1

Manager. The Operations Manager directly oversees the five Peaker Control Operators. The Operations 2

Manager also regularly inspects the peaker plant locations. 3

The five Peaker Control Operators work rotating 12-hour shifts to ensure availability of 4

the peaker plants around the clock. Normally, one Peaker Control Operator is on shift at any given time. 5

It takes five shifts to staff a position around the clock (including coverage for vacation schedules, illness, 6

jury duty, and similar time off). The Operations Manager also has five Peaker Operator Mechanics 7

reporting directly to him. The Operator Mechanics perform typical field operations duties such as 8

routine inspections and monitoring of equipment. They also perform certain preventative maintenance 9

routines, and support other maintenance activities. 10

A Maintenance Manager also supports the Peaker Manager. The Maintenance Manager 11

has primary responsibility for planning and performing all day-to-day routine maintenance, and overhaul 12

outage maintenance. The Maintenance Manager has maintenance journeymen who report to him, which 13

include five Instrument, Control & Electrical (ICE) Technicians and three Machinist Mechanics. This 14

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maintenance staff performs most preventive maintenance work, and performs repairs and corrective 1

maintenance work as such needs arise. 2

A Safety Environmental Specialist (SES) assists the Peaker Manager. The specialist 3

works with the Peaker Manager to oversee all safety and environmental compliance activities for the 4

peakers and associated personnel. These activities include routine environmental reporting, safety 5

inspections, routine refresher training for the other peaker employees, and similar tasks. An Accounts 6

Budgets Analyst (ABA) also assists the Peaker Manager. This analyst works with the Peaker Manager 7

to oversee all budgets and accounting activities for the peakers. The ABA has overall responsibilities 8

associated with the Central Warehouse that supports the entire Peaker Division. The Peaker Division 9

employs an Accounting Clerk who performs front desk receptionist duties, shipping/receiving, and 10

miscellaneous accounting and procuring activities. 11

International Brotherhood of Electrical Workers (IBEW) Local 47 represents all 12

operating and maintenance journeymen personnel, and the Accounting Clerk (a total of 19 of the 24 13

peaker section employees). Other groups within SCE’s Power Production Department (PPD) support 14

the peakers, but do not report to the Peaker Manager as these groups also perform work for the 15

department's other power plants. 16

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III. 1

OPERATION OF THE PGMA (AUGUST 2007 THROUGH NOVEMBER 2007) 2

This section of testimony sets forth for Commission review the operation of the PGMA for 3

the period August 2007 through November 2007.4 In accordance with Resolution E-4031, SCE 4

records its actual revenue requirement (i.e., incremental O&M expenses, book depreciation 5

expense,5 an authorized return on recorded rate base, and applicable taxes) associated with the 6

peaker generation units in the PGMA.6 In addition, SCE transfers amounts recorded in the PGMA 7

monthly to the Generation Sub-account of the BRRBA. During the period August 2007 through 8

November 2007, SCE transferred $11.175 million, including interest of $0.023 million, from the 9

PGMA to the Generation Sub-account of the BRRBA. 10

Table III-1 below summarizes recorded activity in the PGMA for the period August 2007 11

through November 2007. 12

4 Consistent with Resolution E-4031, SCE is authorized to record the revenue requirement associated with the peaker units once

they became operational. Four of the five peakers became operational in August 2007. 5 In its 2009 GRC, SCE estimates that the five peaker generation units will each have an approximate twenty-five (25) year life

span (see SCE-11, Volume 3, page 55 in A.07-11-011). 6 Fuel-related expenses associated with the peaker generation units are submitted for Commission review and approval in SCE’s

ERRA Reasonableness of Operations proceedings filed in April.

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Table III-1

1. Beginning Balance -

2. Expenses3. O&M 1,279

4. Capital Revenue Requirement5. Depreciation 2,494 6. Return 5,352 7. Taxes 2,027 8. Subtotal 9,872

9. Monthly (Over)/Under-Collection 11,152

10. Interest 23

11. Balance Before Transfer to BRRBA 11,175

12. Monthly Transfer to BRRBA (11,175)

13. Ending Balance -

Peaker Generation Memorandum AccountRecorded August - November 2007

($000)

1

Each month SCE records the capital-related revenue requirement associated with the 2

recorded net plant investment. As shown on Line 8 of Table III-1, the amount of capital-related 3

revenue requirement recorded in the PGMA for the months of August through November 2007 4

totaled $9.872 million. The capital-related revenue requirement includes: (1) depreciation expense 5

based on the currently proposed life span in A.07-11-011; (2) return based on the currently 6

authorized 2007 rate of return on rate base (8.77%);7 and (3) associated taxes.7

7 See D.05-12-043, as modified by D.06-08-026.

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IV. 1

OPERATION AND MAINTENANCE EXPENSES 2

As shown on Line 3 of Table III-1 above, during the period August 2007 through November 3

2007, SCE recorded $1.279 million of incremental Operation and Maintenance (O&M) expenses in 4

the PGMA associated with the four operational peaker generation units. The following testimony 5

demonstrates the reasonableness of those O&M expenses. 6

As shown in Table IV-1, during the time period of August 2007 through November 2007, 7

SCE recorded $1.279 million of Peaker O&M expense. These O&M expenses were incurred at each 8

of the four operating peaker sites, and at the Peaker Operations Center at Mountainview, and the 9

Peaker facility at Westminster. 10

Table IV-1 Peaker Record Period O&M Expenses by Location

($Thousands)

Peaker O&M expense can be divided in two main categories: Labor and Non-labor. Peaker 11

Labor expenses consist of normal time labor for all peaker section employees, plus overtime labor 12

for certain of the peaker staff, as well as the labor for certain support activities provided by other 13

PPD work groups. Non-labor expenses consist of all other costs including materials, contractor 14

support, rental equipment, water and other utilities, information technology support, vehicles, and 15

support provided to the peakers by other PPD divisions. 16

The recorded peaker O&M costs are incremental to the costs associated with O&M activities 17

performed at other SCE power plants and are not funded through SCE’s GRC revenue requirement 18

authorized in A.06-05-016 (SCE’s 2006 Phase 1 GRC Decision). Costs are only defined as 19

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incremental if the costs: (1) would not have been incurred “but for” the acquisition and installation 1

of the peakers; and (2) are not funded through existing rates. As discussed above, the peaker 2

organization and its staffing is a new organization that did not exist prior to the launch of the peaker 3

projects. 4

A. Labor Costs 5

Peaker Labor costs reflect the peaker staffing levels, the pay rates specified in the IBEW 6

collective bargaining agreement, and the salaries for management and professional employees as 7

specified in SCE’s Compensation Integration Program. During August-November, 2007, SCE 8

incurred a total Peaker O&M Labor cost of $659,000, of which approximately 22% was for over-9

time Labor. These labor and overtime costs are recorded in several FERC accounts. 10

SCE’s staffing level for the peakers reflects the number of employees required to start all 11

peakers approximately simultaneously, on very short notice, at all hours of the year. SCE's staffing 12

target to achieve these objectives is 24 personnel, consisting of 19 union-represented employees and 13

5 management employees. During much of the time period of August through November 2007, 14

peaker staffing was at these target levels. However, actual staffing levels can vary above and below 15

this target, due to normal employee turn-over and fluctuations in work activity. 16

While the target is a simultaneous start-up of all peaker units, SCE does not expect to 17

perform such simultaneous start-ups frequently. During August through November 2007, many 18

service runs did not involve operating all four peakers simultaneously. SCE dispatched only the 19

number of peakers required for the circumstances. If we learn over time that we need to 20

simultaneously start all peaker units more frequently, then SCE might have to increase staffing by 21

some additional number of employees. In general, future operating and maintenance experience 22

gained over the next several months or years might warrant adjustments to the staffing plan. 23

In addition to each employee's nominal 40-hour work week (which is typically paid at 24

“straight time”), SCE incurs overtime labor in power plants which require around-the-clock 25

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staffing.8 Overtime labor is incurred during periods of high work activity, when expedited repairs 1

require staff to work extended hours or during their normal days off, and when needed to handle the 2

job duties of employees who are off work due to vacation, jury duty and similar circumstances. 3

B. Non-Labor Costs 4

Non-Labor costs include contract labor, materials, and supplies for the following activities: 5

(1) major overhaul maintenance, (2) routine annual maintenance, (3) water, ammonia and other 6

consumables, and (4) miscellaneous. 7

1. Major Maintenance 8

No major maintenance O&M expenses were required during August to November 9

2007. Most equipment repairs were performed by the equipment suppliers under warranty. 10

Warranty coverage will generally extend for one year from the commencement of operations. 11

2. Routine Annual Maintenance 12

As the plants are still relatively new, and as the peakers were still closely supported 13

by GE and other equipment suppliers while remaining construction tasks were continuing, SCE 14

incurred relatively little routine maintenance expense beyond its Labor costs. 15

3. Water, Water Treatment, Ammonia, and Other Supplies and Consumables 16

The peakers consume water to provide additional turbine power output and to reduce 17

NOx output. The evaporative coolers also use water to reduce the temperature of the inlet air to the 18

air compressor section of the turbine. Air inlet cooling also increases turbine power output, in 19

addition to improving the turbine's fuel economy (i.e., heat rate). 20

Water contains many minerals that, if not removed, would deposit upon the 21

compressor stages and turbine blade stages over time. These deposits would reduce compressor and 22

turbine performance, increase maintenance costs, and reduce reliability as deposits (and the 23

associated corrosion) increase the likelihood of failure of the high-speed rotating parts. For this 24

reason, SCE treats the water prior to use. The water must pass through a demineralizer and reverse 25

8 This generally does not apply to our exempt salaried employees.

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osmosis system, which removes the minerals and other impurities. The peakers use rented portable 1

units for water treatment. 2

Water treatment, as well as other plant activities such as cleaning of equipment, 3

generates wastewater. Because of environmental requirements governing wastewater treatment and 4

discharge, the peaker plants cannot economically treat and dispose of this industrial wastewater on 5

site. SCE has contracted with a qualified vendor to collect and appropriately dispose of industrial 6

wastewater off site. 7

The peakers require use of chemicals to perform water testing in the small on-site 8

laboratories at each plant. The plants also consume greases, oils, and other lubricants, and cleaners. 9

The SCR system for NOx emissions control consumes aqueous ammonia to activate the catalyst. 10

The plant consumes various industrial gases for the CEMS, and for certain maintenance activities 11

(e.g., gas welding). 12

The combustion turbine inlet air filters need regular replacement, as they foul. 13

Maintenance employees need shop rags, drill bits, batteries, and similar items. The peaker office 14

staff uses paper and other office supplies. 15

Our recorded costs during August through November 2007 included these activities. 16

However, given the normal billing cycles of our material suppliers and service contractors, our 17

recorded costs for these activities for the period were relatively low. We expect our monthly 18

recorded costs to increase as supplier invoices, and our resulting payments, reach a steady-state 19

level. 20

4. Miscellaneous Non-Labor Costs 21

The peakers incur other miscellaneous costs for general management and 22

administration. For example, each peaker site generates some waste material, such as spent filters, 23

broken parts, and the like. Trash hauling contractors must properly dispose of this material. 24

Operating and maintaining the peakers generates hazardous wastes. This waste must be properly 25

packaged and disposed of in accordance with law. Similarly, the peakers operate under permits 26

governing air emissions, which require payment of annual fees and other related costs. 27

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Also included in general management and administration costs are fees associated 1

with the use of vehicles. The SCE Fleet Operations department provides vehicles for traveling 2

among the facilities and used in the course of operations, maintenance and management oversight of 3

the current four peaker locations and two control centers. Fleet Operations charges back to the 4

peaker section the costs for lease of vehicles and their maintenance, and lease of mobile cranes, 5

forklifts, service trucks and other equipment. These types of costs are included in the Peaker O&M 6

expenses. 7

SCE also incurs Information Technology (IT) costs to run the peakers. Personnel 8

require personal computers, telephones, pagers, and radios (walkie-talkies) to communicate. Peaker 9

plants are located many miles apart. SCE dispatches and controls them from central locations at the 10

Mountainview power plant and the SCE Westminster facility, via a data network. IT includes the 11

processes and equipment from tracking spare parts, submitting time for payroll, and document 12

management and retrieval of operating and maintenance data and procedures. 13

Other groups within PPD also support the operations and maintenance of the peakers. 14

These activities include support from the PPD water chemistry lab, the PPD Engineering and 15

Technical Services division, the PPD Training section, and the PPD Administrative and Business 16

Planning divisions. These centralized service groups also support certain activities common to the 17

entire department (i.e., managing the department’s computerized maintenance tracking and 18

scheduling system and similar tasks). 19

Our recorded costs during August through November 2007 included the above 20

activities. However, as is the case with the costs discussed in the preceding section, the costs for this 21

section were low during the period given the normal billing cycles of our material suppliers and 22

service contractors. We expect our monthly recorded costs to increase as supplier invoices, and our 23

resulting payments, reach a steady-state level. 24

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C. Recorded Costs by FERC Account 1

Our peaker O&M costs record to nine FERC accounts, as summarized in Table IV-2 below. 2

The following sections provide more details on O&M activities contained within each FERC 3

account. 4

Table IV-2 Peaker Record Period O&M Expenses by FERC Account

($Thousands)

5

1. FERC Account 546 – Operation Supervision and Engineering 6


Account 546 includes Labor and Non-Labor expenses incurred in the general 8

supervision of power generating stations. 9


The expenses recorded from August 2007 through November 2007 for 11

Account 546 are $37,498.51, including $32,642.64 for Labor expense and $4,855.87 for Non-Labor 12

expense. 13

The Labor expenses consist of the salary of the Peaker Manager, the 14

Operations Manager, a business analyst and direct labor charged by the PPD home office staff. 15

The Non-Labor expense includes training expenditures, some outside contract 16

services for operations support, travel expenses for the employees charging to this account and other 17

home office support and PPD staff allocation related to general management and administration. 18

-20-

2. FERC Account 548 –- Generation Expenses 1


Account 548 includes the cost of labor, materials, and expenses incurred in 3

operating prime movers, generators and electric equipment at power generating stations up to the 4

point where electricity leaves for conversion for transmission or distribution. It includes Labor and 5

Non-Labor expenses for: direct supervision of operations, equipment operators who directly operate 6

and control station equipment, and the expense of chemicals consumed for water treatment and 7

emission control. Additionally, it includes the cost for environmental fees, permits, monitoring and 8

reporting. 9


The expenses recorded from August 2007 through November 2007 for this 11

account are $482,497.96, including $255,900.54 for Labor expenses and $226,597.42 for Non-Labor 12

expenses. 13

The Labor expenses consist of part of the salary of the Control Operators and 14

Operator Mechanics that physically operate the plants. The Labor expenses also include Labor for 15

PPD’s chemical technicians charging to peakers. 16

The Non-Labor expenses include the cost of various chemicals used in 17

operating the peakers. The significant expense is for demineralized water treatment service and 18

aqueous ammonia used for emissions control. The account also includes costs of operating permits, 19

emissions permits, and fees. This account includes expenses for travel, mileage, and overtime meals 20

for personnel who charge their Labor expenses to this account. 21

3. FERC Account 549 – Miscellaneous Other Power Generation Expenses 22


FERC Account 549 includes Labor and Non-Labor costs that are not readily 24

assignable to other operating accounts. A list of typical items includes: 25

1) General management and administration 26

2) Clerical support 27

-21-

3) Labor relations expenses 1

4) Safety and training 2

5) Facility security 3

6) Environmental compliance activities 4



account are $406,709.12 including $127,478.52 for Labor expense and $279,230.60 for Non-Labor 7

expense. 8

The Labor expenses consist of the salary of the Station Accounting Clerk and 9

Safety & Environmental Specialist (SES). Additional Labor is for training control operators and 10

operator mechanics, and engineering support, when necessary, from PPD’s Engineering & Technical 11

Services staff. 12

The Non-Labor expenses include certain supplies and expendables, water, 13

telephone service and radios. 14

4. FERC Account 550 – Rents 15


Rents include expense for real property rentals used, occupied or operated. 17



account are $18,459.04 for Non-Labor expense only. The Non-Labor expenses include the cost of 20

rental equipment at the peaker locations. 21

5. FERC Account 551 – Maintenance Supervision and Engineering 22


Account 551 includes Labor and Non-Labor expenses incurred in the general 24

supervision, direction and engineering activities needed for maintenance. 25

-22-



account are $34,945.89 including $32,314.38 for Labor expense and $2,631.51 for Non-Labor 3

expense. 4

The Labor expenses for this account consists of the salary of the maintenance 5

manager. The Non-Labor expenses include related incidental expenses. 6

6. FERC Account 553 – Maintenance of Generating and Electric Plant 7


Account 553 includes the cost of labor, material, contractor services and other 9

expenses necessary to maintain and repair generating equipment including prime movers, generators 10

and accessory electric equipment. 11



account are $180,711.12 including $151,738.93 for Labor expenses and $28,972.19 for Non-Labor 14

expenses. 15

The Labor expenses consist of part of the salaries of the machinist mechanics 16

and ICE technicians. 17

The Non-Labor expenses include the cost of materials to repair and maintain 18

plant generating equipment. 19

7. FERC Account 554 – Maintenance of Miscellaneous Other Power Generation 20

Plant 21


Account 554 includes the Labor and Non-Labor expenses incurred to maintain 23

and repair other plant equipment, such as the compressed air system, fire suppressing equipment, 24

and shop equipment. This account also includes maintenance training expense, vehicle expense, and 25

consumable supplies. 26

-23-



account are $71,821.58 including $16,345.80 of Labor expenses and $55,475.78 for Non-Labor 3

expenses. 4


and ICE technicians when performing their duties to repair and maintain balance of plant equipment. 6

Additional labor is for training machinist mechanics and ICE technicians. 7

The Non-Labor expenses include the cost of materials to repair and maintain 8

the balance of plant systems. Non-Labor expenses also include fees associated with the vehicle fleet 9

assigned to the peaker units. 10

8. FERC Account 562 – Operations of Station Transmission Equipment 11


Account 562 includes the Labor and Non-Labor expenses involved in system 13

operation coordination, equipment operation/monitoring, and operating procedures development in 14

relation to station transmission equipment. The related plant equipment includes the main step-up 15

transformers, line-side voltage connections, and switching equipment. 16



account are $1,129.01 including $1,083.26 of Labor expenses and $45.75 for Non-Labor expenses. 19

9. FERC Account 570 – Station Transmission Equipment 20


Account 570 includes the Labor and Non-Labor expenses for maintenance on 22

station transmission equipment. It relates to costs associated with main step-up transformers, line-23

side voltage connections, and switching equipment. 24

-24-



account are $45,492.05 including $41,344.05 of Labor expenses and $4,148.00 for Non-Labor 3

expenses. 4


and ICE technicians when performing their maintenance duties on transmission related equipment. 6

The Non-Labor expenses primarily include travel, mileage, and overtime meals for personnel who 7

charge their Labor expenses to this account.8

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V. 1

PEAKER ACQUISITION AND INSTALLATION COSTS 2

A. Overview 3

The total direct capital costs recorded for each peaker site, through the end of November 4

2007, are as shown in the following table. 5

Table V-1

Site Actual Recorded Cost (11/30/07) Forecast Final Cost

Barre $61,838,696 $70,412,671Center $63,480,526 $69,969,501Grapeland $55,632,349 $60,529,324Mira Loma $54,885,613 $59,549,588Westminster Offices, B/U Ctl Facility, and Warehouse

$1,097,753 $1,097,753

Mountainview Ctl Room

$419,455 $419,455

Capital Spare Parts $606,143 $1,800,000Grand Total $237,960,635 $261,978,292

Although these four peakers and the two central facilities are all installed and operational, 6

certain costs have not yet been recorded, either because (1) the associated work has been performed 7

but these costs have not yet gone through the billing and payment cycle, or (2) the work is post-8

startup work that has not yet been completed. 9

1. Committed Costs Not Yet Recorded 10

There are costs remaining for the four peaker sites that have been incurred, but not yet 11

recorded. This includes costs that have recorded since November 30, 2007, and invoices that are 12

currently being processed, but have not yet recorded. This is estimated at a total of approximately 13

$14,855,900. 14

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2. Forecast of Remaining Work to be Performed at Peaker Sites Currently In 1

Service 2

While the units are now in commercial operation, certain items of work remain to be 3

performed. The majority of these work items are expected to be completed during the first half of 4

2008. 5

a. Barre Peaker 6

In the case of the Barre unit, landscaping and fencing improvements to the perimeter 7

of the existing substation and adjacent to the peaker on its southern exposure was agreed to with the 8

City of Stanton to mitigate the visual impact of the peaker installation. This work is estimated at 9

$4,400,000. This work could not be performed until the construction of the peaker plant was 10

complete, and internal fencing and sound walls surrounding the unit were completed. Additional 11

study was also required by the City of Stanton before issuing the permit to complete connection of 12

the sewer outfall line to the City’s sewer system. It is expected that completion of this connection 13

will cost $10,000. These modifications are expected to be completed in the first half of 2008. 14

b. Center Peaker 15

Restoration of landscaping removed at the Center site could not be initiated until the 16

construction of the peaker was completed. Work is in progress to complete landscaping plans that 17

will visually mitigate the peaker installation. Drawings are being prepared that will be reviewed 18

with neighboring residents for their input regarding the visual mitigation. In addition, a sound wall 19

will be incorporated with the landscaping plan to further reduce noise impacts from operation of the 20

peaker unit. The costs of the landscaping improvements and installation of the sound wall are 21

estimated at $1,500,000. Road modifications from the existing substation entry to allow access to 22

the peaker unit are forecast at $815,000. Additional information also was required by the Sanitation 23

Districts of Los Angeles County before the permit is granted to complete connection of the sewer 24

outfall line to the county sewer system. It is expected that completion of this connection will cost 25

$10,000. These modifications are expected to be completed in the first half of 2008. 26

-27-

c. Mira Loma Peaker 1

In connection with a residential development project in the City of Ontario, 2

infrastructure improvements are planned for the street, water, and sewer systems along Milliken 3

(also known as Hamner) Avenue at the peaker site. Currently, neither the vehicle entry into the 4

peaker site nor the vehicle entry into the adjoining SCE substation has traffic signals. Because of the 5

increased traffic flow, modification of both the substation and the peaker entries are needed to allow 6

alignment with an existing intersection, which has signals, to allow safe entry and exit from both 7

SCE facilities. SCE incorporated the entry improvements as part of the peaker installation and is 8

working with City of Ontario and the developer to coordinate this entry modification with the 9

construction of the street improvements being performed by the developer. It is expected that this 10

construction will occur in the first half of 2008, and is forecast to cost $500,000. The developer is 11

also working with the City on the water and sewer improvements along the street, which will 12

become part of the City of Ontario water and sewer system. The timing of the water and sewer 13

connections is currently not known, but the peaker plant will be required to connect to these 14

facilities. 15

d. Grapeland Peaker 16

In connection with development of SCE’s Rancho Vista substation, which is adjacent 17

to the Grapeland peaker, infrastructure improvements are planned to control storm water drainage 18

from the peaker site and to adjust for the final evaluation differences between the two sites. To 19

accomplish this, drainage improvements are planned at a forecast cost of $143,000, and a retaining 20

wall is also planned at a forecast cost of $590,000. 21

3. Total 22

In summary, the total cost (including the forecasted and committed costs described 23

above) for the first four units, when completed, is expected to be $261,978,292. 24

Ultimately, the cost increases as compared to SCE’s original 2006 estimate – which 25

was approximately $50 million per peaker -- can be attributed to the limited time available to have 26

the units operational by August 1, 2007, in two respects: (1) if more time had been available to 27

-28-

allow for site selection and for preliminary engineering to occur, the original estimate would have 1

increased; and (2) overall labor costs increased as a result of the limited time available to complete 2

the units. A project of this type would typically take approximately two to two-and-a-half years to 3

complete. As noted previously, SCE was successful in having four separate peaker units available 4

by August 1, 2007. This proved beneficial to both CAISO and SCE’s customers, as the units were 5

called upon to operate as soon as the serious heat storm event of the week of August 27, 2007, as 6

well as on later occasions. 7

B. Cost of Materials 8

1. Cost of Major Peaker Components 9

The turbine, generator, and major balance of plant equipment for each peaker project 10

were purchased from GE. The unit cost of the equipment provided for each site is as shown in the 11

following table. 12

Table V-2

Item No.

Equipment Unit Price(s) (U.S. Dollars)

Number of Units

Subtotal (U.S. Dollars)

001 LM6000 $14,436,000.00 1 $14,436,000.00002 Gas Fuel Compressor Package $958,800.00 1 $958,800.00003 Gas Fuel Filter / Coalescer Skid $91,900.00 1 $91,900.00004 Instrument Air Compressor Skid $95,900.00 1 $95,900.00005 Continuous Emissions Monitoring

System (CEMS) $263,000.00 1 $263,000.00

006 LM6000PC Selective Catalytic Reduction System

$2,782,400.00 1 $2,782,400.00

007 Ammonia Storage Tank and Forwarding Pump Skid

$277,700.00 1 $277,700.00

008 Turbine Package First Fill Lubricants

$15,700.00 1 $15,700.00

009 Power Control Module $182,800.00 1 $182,800.00010 Main Power Transformer – 13.8kV

to 66kV $844,600.00 1 $844,600.00

011 Medium Voltage Switchgear / Generator Breaker

$210,600.00 1 $210,600.00

012 Auxiliary Transformer – 13.8kV to 4.16 kV

$82,100.00 1 $82,100.00

013 Auxiliary Transformer – 13.8kV to $73,000.00 1 $73,000.00

-29-

Table V-2

Item No.

Equipment Unit Price(s) (U.S. Dollars)

Number of Units

Subtotal (U.S. Dollars)

480V 014 Combustion Turbine Motor Control

Center $46,000.00 1 $46,000.00

015 SCR/COR Motor Control Center $34,500.00 1 $34,500.00016 125 Volt DC Battery System $61,200.00 1 $61,200.00017 Blackstart Natural Gas-Fired

Generator Package $518,200.00 1 $518,200.00

018 Blackstart Natural Gas-Fired Control System

$120,700.00 1 $120,700.00

019 Supervisory Control System $290,100.00 1 $290,100.00 Total Fixed Price per Site $21,385,200.00

In addition to the fixed price equipment above, GE also provided rates for storage of 1

the units (estimated at $346,500 for all units), an estimate for the transportation of the units from 2

point of manufacture to each of the respective sites ($868,000 per unit), training of the O&M 3

personnel ($50,000), Startup and Commissioning of each unit ($436,200 per unit), and a letter of 4

credit ($90,000). 5

At the time SCE issued its purchase order to GE, the total scope of supply for all five 6

units was $113,983,500. As detailed engineering progressed, changes to the above equipment were 7

made that increased the total forecast cost of the GE scope of supply to $125,814,184 (all five units). 8

The total recorded cost of the GE scope of supply for the first four units is as shown in the following 9

table. 10

Table V-3 Site Cost of GE Scope of Supply

Barre $24,479,094 Center $24,679,443

Grapeland $24,618,275 Mira Loma $24,562,159

Total $98,338,971

-30-

2. Remaining Balance of Plant Equipment Not Provided by General Electric 1

A significant amount of additional equipment not within the GE scope of supply was 2

needed in order for the units to be functional, safe, and environmentally compliant. A list of the 3

additional equipment is shown below, with explanatory qualifying comments as applicable. 4

Table V-4 Equipment Description Comments

Oil Water Separator Demineralized water storage Tanks

Fire/Service water storage Tank Barre Only Wash Water Tank and Waste Oil Tank

Demineralized water Transfer pump Skid

Service water Pump skid Barre Only Waste Water sumps and Sump Pumps

Lift Stations and sewer manholes Barre and Center Only Ammonia Containment Vault Valves, Lot Shower/Eyewash stations Cable, Lot Instrumentation, Lot Electrical Manholes/Vaults Fire Hydrants Fire system Post indicating Valves

Fire Alarm system Cathodic protection system Electrical Dead End structure ISO meter panel Data Processing gateway panel Protective relay Panel Electrical disconnect switches Telecom Panels Remote terminal unit Panels Routers for Data Processing Gateway (DPG) and CA-ISO meters

Schweitzer protective relays Digital fault recorders Fencing

-31-

Bulk materials such as concrete, rebar, valves, cable, and the like are included as part 1

of the construction costs summarized in Section E below. The summary level, balance of plant cost 2

per site (including the taxes associated with all of the above materials, both the GE supplied 3

equipment and the non-GE balance of plant equipment) is shown in the following table. 4 Table V-5

Site Cost Barre $3,212,235Center $3,303,955Grapeland $2,835.052Mira Loma $2,904,915Total $12,256,157

C. Cost of Gas Pipeline Installation 5

A collectible work order agreement was established to engineer, purchase materials, and 6

construct the gas supply pipelines from the point of interconnection at the Southern California Gas 7

Company (SoCalGas) system to each of the peaker sites. SoCalGas performed this work on a 8

“turnkey” basis. In addition to the construction of the pipeline, SoCalGas also installed a metering 9

station and telemetry at each site for monitoring the gas flow and pressure. The length and diameter 10

of each line is as shown below. 11

Table V-6 Site Diameter, inches Approximate length, feet

Barre 8 13,200 Center 8 18,000 Grapeland 6 6,000 Mira Loma 6 9,100

The costs borne by SCE are shown below, and include the Income Tax Component of 12

Contributions and Advances (ITCCA) in aid of construction in accordance with Ordering Paragraph 13

3.a. of D.87-09-026 as modified by D.87-12-026. The ITCCA tax factor is 35%. 14

Table V-7 Site Direct Cost ITCCA Total

Barre $4,449,289 $1,557,251 $6,006,540Center $6,513,369 $2,279,679 $8,793,048Grapeland $1,978,155 $692,354 $2,670,509Mira Loma $2,756,102 $964,635 $3,720,737Grand Total $15,696,915 $5,493,919 $21,190,834

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D. Cost of Electrical Interconnection 1

Each of the peaking units was connected to the 66kV subtransmission system. As with any 2

other generator that connects to SCE’s electrical subtransmission system, SCE’s Generation 3

Business Unit (GBU) entered into a Large Generator Interconnection Agreement (LGIA) and a 4

Service Agreement for Wholesale Distribution Service with SCE’s Transmission and Distribution 5

Business Unit (TDBU). The LGIA specifies the terms for TDBU to provide Interconnection 6

Service, for TDBU to engineer, design, construct, install, own, operate, and maintain, the 7

Distribution Provider’s Interconnection Facilities and Distribution Upgrades, and for GBU to pay for 8

such facilities. 9

As with any generator wishing to connect to the SCE electrical system, an interconnection 10

application was filed for each peaker, and was subject to the cost of distribution and network 11

upgrades based on other existing projects that had filed ahead of it. The direct cost of electrical 12

interconnection recorded as of the end of November 2007 for each site is as shown in the following 13

table. 14

Table V-8 Site Estimated Cost

Barre $1,711,000 Center $1,955,000 Grapeland $1,898,000 Mira Loma $1,681,000 Grand Total* $7,245,000 *Cost is subject to true up in accordance with the LGIA when work orders are closed.

E. Costs of Engineering, Construction and Home Office 15

A contract to construct the five peakers was awarded to Irwin Industries. As of November 16

30, 2007, $79,671,992 has recorded under the contract for the first four units, as shown in the 17

following table. As discussed above, committed costs remaining to record for the first four units 18

total an additional $14,855,895. 19

-33-

1

Table V-9 Site Recorded Cost

Barre $22,349,775 Center $20,273,136 Grapeland $19,312,572 Mira Loma $17,736,509 Grand Total $79,671,992

A contract to perform the engineering of all five of the peaker plants was awarded to Worley 2

Parsons. As of the end of November 2007, the recorded costs for the four completed plants are 3

approximately $3,879,800. Some as-built drawings are still being completed; currently committed 4

costs are approximately $40,000. 5

Worley Parsons was also awarded a contract to provide field engineering support and 6

construction management support. Recorded costs for this support as of the end of November 2007 7

are $4,284,583. 8

In house costs to support the project as of the end of November, 2007, including contract 9

forces to augment SCE’s Engineering and Technical Services work force, totaled $7,833,929. Other 10

miscellaneous costs, such as insurance, and the deposit fee for the system impact studies performed 11

by SCE, totaled $1,540,918 as of the end of November. 12

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VI. 1

COST RECOVERY FROM ALL BENEFITING CUSTOMERS 2

A. Background 3

In its Order Instituting Rulemaking (R.) 06-02-013, the Commission had stated that a major 4

goal of that proceeding was to examine the need for additional policies to support new generation 5

and long-term contracts for California, including consideration of transitional and/or permanent 6

mechanisms (cost allocation and benefit sharing) that could ensure the construction of, and 7

investment in, new generation in a timely fashion. In addition to new generation, the Commission 8

also indicated its interest in capacity markets and exploring the concept and mechanisms of capacity 9

markets. 10

In D.06-07-029 (issued in R.06-02-013), the Commission adopted (among other things) a 11

modified Joint Parties proposal by establishing a cost allocation mechanism that allocates the net 12

costs of new generation to all “benefiting customers”9 in an Investor-Owned Utility’s (IOU’s) 13

service territory. This allocation was designed to prevent applicable costs from being incurred solely 14

by the IOU’s bundled service customers. Ordering Paragraph 6 of D.06-07-029 stated: “Only non-15

utility owned generation chosen by SCE in the RFOs will be eligible for this newly adopted cost 16

allocation mechanism.” However, the Commission in the ACR expressly allowed SCE “in its later 17

rate application” (i.e. the instant Application) to request different ratemaking treatment for the 18

peakers than that established in D.06-07-029 for utility-owned resources. As discussed above, as an 19

interim measure and consistent with Resolution E-4031, SCE has been transferring the revenue 20

requirement associated with the on-line peakers to the generation sub-account of the BRRBA. 21

Amounts recorded in the generation sub-account of the BRRBA are recovered only from SCE’s 22

bundled service customers through generation rate levels. 23

9 Footnote 21 of D.06-07-029 defines “benefiting customers” as all bundled service customers, Direct Access (DA) customers and

Community Choice Aggregators (CCA) customers. Benefiting customers also include customers who are located within a utility distribution service territory but take service from a local Publicly Owned Utility (POU) subsequent to the date that new generation goes into service.

-35-

B. Cost Recovery Proposal 1

Consistent with the ACR, SCE requests authorization to apply “the cost- and benefit-sharing 2

mechanism” established under D.06-07-029 to all of these peakers by allocating the peakers’ costs to 3

all benefiting customers rather than only among SCE’s bundled service customers. Although these 4

peakers are SCE-developed and -owned, this is the appropriate ratemaking treatment of the costs of 5

these peakers, as explained in this section of testimony. 6

At page 7 of the ACR, the ACR expressly provided that: 7

8 “Because of the urgent need for capacity for summer 2007 and the unusual 9 steps being taken in this ruling, SCE may choose in its later rate application to 10 request, and the Commission may wish to consider, for resources built 11 pursuant to this ruling, different ratemaking treatment than that established in 12 D.06-07-029 for utility owned resources.” 13

SCE’s request is fair and reasonable, and fully consistent with the overall intent of D.06-07-14

029, given the specific circumstances under which the peakers were authorized and constructed. 15

SCE was directed by the ACR to pursue development of these peakers. As mandated by the ACR, 16

SCE developed the peakers on a rapid time schedule (with associated costs) to help protect all 17

customers from the possibility of peak season capacity shortages as soon as the summer of 2007. 18

Moreover, pursuant to the ACR, SCE designed and sited the peakers to maximize collateral grid 19

reliability benefits to all SCE customers. SCE accordingly proposes to allocate the costs to all 20

“benefiting customers” and to recover those costs through a non-bypassable charge the Commission 21

is establishing in Track 3 of R.06-02-013. Consistent with D.06-07-029 and D.07-09-044, in 22

exchange for paying these costs, the benefiting customers’ Load Serving Entities will receive a pro-23

rata share of the MW capacity of these peakers for demonstrating resource adequacy. 24

C. Modification to the New Generation System Balancing Account 25

In compliance with D.07-09-044, SCE filed Advice 2179-E on November 15, 2007, to establish 26

a New System Generation Balancing Account (NSGBA). The purpose of the NSGBA is to record 27

revenue and costs associated with long-term power purchase agreements (PPAs) associated with 28

non-utility owned (or built) new generation resources. The NSGBA will also record non-bypassable 29

-36-

charge revenues from the New System Generation Charge (NSGC) that is being established in 1

R.06.02-013 (Long Term Procurement Proceeding) to recover these PPA costs from all “benefiting 2

customers” and not just bundled service customers. The balance (i.e., over- or under-collection) 3

recorded in the NSGBA at the end of each year will be included in the non-bypassable NSGC in the 4

subsequent year. At the time of filing this application, the Commission had not yet approved Advice 5

2179-E. 6

If the Commission in this proceeding authorizes SCE to recover the peaker revenue 7

requirement from all benefiting customers, then SCE requests Commission authority to: (1) include 8

the peaker revenue requirement in the non-bypassable NSGC; (2) revise the NSGBA to record the 9

peaker revenue requirement10; and (3) transfer amounts recorded in the generation sub-account of 10

the BRRBA since August 2007 to the NSGBA (i.e, credit the costs that have been recorded in the 11

generation sub-account of the BRRBA, plus interest, and debit the NSGBA). 12

10 Prior to the peaker revenue requirement being included in the 2009 GRC revenue requirement, SCE will record the

actual revenue requirement in the NSGBA. As of the effective date of the 2009 GRC revenue requirement, SCE will record the peaker revenue requirement authorized by the Commission.

-37-

VII. 1

FUTURE REVIEW OF PGMA COSTS 2

Ordering Paragraph 6 of Resolution E-4031 directs SCE to file this instant Application no 3

later than December 31, 2007. Consequently, as has been discussed above, SCE can include in this 4

application only the recorded data for the four peaker generation units through November 2007. 5

SCE requests Commission authority to include the recorded operation of the PGMA during the 6

period from December 2007 through December 2008 in its April 2009 ERRA Reasonableness of 7

Operations filing. 8

Accordingly, SCE would not include amounts recorded in the PGMA for December 2007 in 9

its April 2008 ERRA Reasonableness of Operations filing. Including a single month of recorded 10

PGMA data (i.e., December 2007) in SCE’s April 2008 ERRA Reasonableness of Operations filing 11

would not be administratively efficient for SCE or for the Commission, and would provide no 12

advantage over simply including all 13 months of data within the 2009 proceeding. 13

14

15

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Exhibit 1

Barre Peaker (Stanton, CA)

-39-

Exhibit 2

Center Peaker (Norwalk, CA)

-40-

Exhibit 3

Grapeland Peaker (Rancho Cucamonga, CA)

41

Exhibit 4

Mira Loma Peaker (Ontario, CA)

Appendix A

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF DOUGLAS A. SNOW 3

Q. Please state your name and business address for the record. 4

A. My name is Douglas A. Snow, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company (SCE). 7

A. I am the Manager of Revenue Requirements in SCE’s Regulatory Policy and Affairs (RP&A) 8

Department. As such, I am responsible for overseeing the operation of various Balancing and 9

Memorandum Accounts and the associated disposition of the balances in those accounts for 10

ratemaking purposes. 11

Q. Briefly describe your educational and professional background. 12

A. I graduated from Texas A&M University in May of 1982 with a Bachelors of Science Degree in 13

Industrial Engineering. In June of 1982, I went to work for Southwestern Public Service 14

Company (SPS) in west Texas. While there, I attained a title of Supervisory Engineer and was 15

responsible for revenue requirement calculations and rate design for both retail and resale 16

customers. I filed testimony on behalf of SPS before the Texas Public Utility Commission and 17

the Federal Energy Regulatory Commission. In November of 1993, I went to work for the 18

Southern California Edison Company as a Financial Analyst in the FERC Pricing section in the 19

RP&A Department. While working in the FERC section, I was responsible for the rate design 20

for SCE’s requirements sales for resale, Wheeling Access Charges, and wholesale Distribution 21

Access Charges. In March 1998, I became a Supervisor in the Revenue Requirements division 22

of RP&A, responsible for supervising a group of analysts that oversee the forecasting and 23

recording entries associated with all CPUC regulatory mechanisms. In December 2001, I was 24

promoted to the position of manager in the Revenue Requirements division of RP&A. In August 25

2006, I was promoted to my current position as Manager of Revenue Requirements. I have 26

previously testified before the California Public Utilities Commission. 27

Q. What is the purpose of your testimony in this proceeding? 1

A. The purpose of my testimony in this proceeding is to sponsor portions of Exhibit SCE-1, titled 2

SCE Peakers Costs,, as identified in the Table of Contents thereto. 3

Q. Was this material prepared by you or under your supervision? 4

A. Yes, it was. 5

Q. Insofar as this material is factual in nature, do you believe it to be correct? 6

A. Yes, I do. 7

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 8

judgment? 9

A. Yes, it does. 10

Q. Does this conclude your qualifications and prepared testimony? 11

A. Yes, it does. 12



OF ANTHONY KURPAKUS 3

A. Please state your name and business address for the record. 4

A. My name is Anthony Kurpakus, and my business address is 300 N. Lone Hill in 5

San Dimas, CA 91773. 6

Q. Briefly describe your present responsibilities at the Southern California Edison 7

Company (SCE). 8

A. I am a Project Manager in the Power Production Division. My responsibilities 9

include preparation of information and documentation to support regulatory 10

filings, data requests, and business analyses. 11


A. I received my Bachelor of Science degree in Engineering from Cal State Long 13

Beach in 1975. In 2000 I received my Masters Degree in Project Management 14

from Keller Graduate School of Management. I joined SCE in 1998 in the 15

Hydroelectric Division staff department. In my initial position as a Business 16

Analyst, I provided decision support information for economic analyses, business 17

improvement, capital project justification, and regulatory filings. I assumed my 18

position as a Project Manager in August of 2002. I transferred from the Hydro 19

Division to the Power Production staff of Business Planning & Development in 20

February of 2004. 21


A. The purpose of my testimony is to sponsor the portions of Exhibit SCE-1, titled 23

SCE Peaker Costs, as identified in the Table of Contents thereto. 24


A. Yes, it was. 26


A. Yes, I do. 1

Q. Insofar as this material is in the nature of opinion or judgment, does it represent 2

your best judgment? 3

A. Yes, it does. 4


A. Yes, it does. 6

Paul Phelan Quals.doc -1-



OF PAUL F. PHELAN 3

Q. Please state your name and business address for the record. 4

A. My name is Paul F. Phelan, and my business address is 300 N. Lone Hill, San Dimas, CA 5

91773. 6

Q. Briefly describe your present responsibilities at the Southern California Edison 7

Company. 8

A. I am presently the Manager of the Power Production Department, Engineering & 9

Technical Services. I have management responsibility for the planning, cost, schedule 10

and quality of projects and providing engineering and technical support for the Power 11

Production Department, and other Business Units within SCE. 12


A. I have a Bachelor of Science degree in Mechanical Engineering from the University of 14

Arizona in Tucson, and a Bachelor of Science degree in Metallurgical Engineering from 15

the University of Texas at El Paso. 16

Prior to my current position, I have held various management and engineering 17

positions within Edison in the fossil generation area. 18


A. The purpose of my testimony in this proceeding is to sponsor the portions of Exhibit 20

SCE-1, entitled SCE Peaker Costs, as identified in the Tables of Contents thereto. 21


A. Yes, it was. 23


A. Yes, I do. 25

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 26

judgment? 27

A. Yes, it does. 28


Paul Phelan Quals.doc -2-

A. Yes, it does. 1

PEAKERS COST RECOVERY TESTIMONY...12 ratemaking request in Advice 2031-E (effective November 9,...

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Transcript of PEAKERS COST RECOVERY TESTIMONY...12 ratemaking request in Advice 2031-E (effective November 9,...