2012 General Rate Case

Transcription

1 Application No.: Exhibit No.: SCE-0, Vol. 0 Part 0 & 0, Ch. I-II Witnesses: P. Arons K. Varnell (U -E) 01 General Rate Case Transmission And Distribution Business Unit (TDBU) Volume Part - Transmission And Interconnection Planning Part - Engineering Design And Project Management Chapters I-II Before the Public Utilities Commission of the State of California Rosemead, California November 0

2 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management Table Of Contents Section Page Witness I. TRANSMISSION AND INTERCONNECTION PLANNING... 1 P. Arons A. Introduction And Overview... 1 B. Transmission Interconnection Projects Project Life Cycle.... Projects Discussed In This Chapter... C. Grid Reliability Projects Rio Hondo Substation Circuit Breaker Upgrades... a) Background... b) Project Scope.... Acton Substation Loop-in Project... a) Background... 1 b) Project Scope Victor rd A Bank and Rebuild of kv Switchrack... 1 a) Background... 1 b) Project Scope East Kern Wind Resource Area (EKWRA)... 1 a) Background... 1 b) Project Scope... 1 D. Renewable Interconnection Projects Tehachapi Renewable Transmission Project (TRTP) Seg. and Seg.... a) Background... -i-

3 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management Table Of Contents (Continued) Section Page Witness b) Segment Project Scope... c) Segment Project Scope.... Eldorado Ivanpah Transmission Upgrades... a) Background... b) Project Scope... E. Additional Projects Included Strictly For Their Telecommunication Costs Devers - Colorado River (DCR) (formerly Devers Palo Verde No. 00 kv T/L... a) Background... b) Telecommunications Scope.... Tehachapi Renewable Transmission Project - Segments,,... a) Background... b) Telecommunications Scope.... Rector SVC and BC/SJV RAS... 0 a) Telecommunications Scope Coram Energy Brodie Wind I and II... 1 a) Telecommunications Scope... 1 F. Projects With Less Than $1 Million in CPUC-Jurisdictional Costs... 1 II. ENGINEERING DESIGN AND PROJECT MANAGEMENT... K. Varnell A. Introduction... B. Work Description... -ii-

4 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management Table Of Contents (Continued) Section Page Witness 1. Ongoing Operation and Maintenance.... Infrastructure Replacement.... System Expansion/Load Growth... C. Organization Engineering... 1 a) Civil/Structural Engineering... 1 b) Apparatus Engineering... 1 c) Protection and Automation Engineering... 1 d) Substation Projects Engineering... e) Transmission Engineering... f) Standards and Publications... g) Compliance and Quality Engineering... h) Added/Interconnection Facilities Engineering... i) Project Engineering.... Project Management Office (PMO).... Shop Services and Instrumentation Division (SSID)... a) Mechanical Services... b) Metrology Services... c) Transformer Shop Services... d) Standards Laboratory Services.... Engineering and Technical Support... a) Special Project Development... -iii-

5 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management Table Of Contents (Continued) Section Page Witness b) Business Management... c) Customer Grid Interconnection Application Management... D. Cost Summary Operations and Maintenance (O&M)... a) Transmission/Substation Operation Supervision and Engineering... (1) Historical Analysis for Engineering Activities... 0 () Forecasts for Engineering Activities... () Historical Analysis for SSID Lab Tools... () Forecasts for SSID Lab Tools... () Historical Analysis for Miscellaneous Employee Expenses... () Forecasts for Miscellaneous Employee Expenses... b) Engineering, Planning and Protection Studies... (1) Historical Analysis... () Forecasts... c) Sub-Accounts.0 &.0 Shop Services Distribution and Maintenance of Line Transformers... (1) Historical Analysis... 0 () Forecasts SSID Capital Expenditure... -iv-

6 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management Table Of Contents (Continued) Section Page Witness a) Description... b) Necessity... c) Historical Analysis... d) Cost Forecast.... Allocated Costs... a) Engineering and Project Management Allocated Costs Summary... (1) Forecasts... b) D001 Cost Summary... (1) Forecasts... E. Resource Forecasts Labor Resources... a) Headcount... (1) Engineering, PMO and Technical Support Groups... () Forecast... () Shop Services and Instrumentation Division... () Forecast Vehicles... Appendix A Witness Qualifications -v-

7 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management List Of Figures Figure Page Figure I-1 General Jurisdictional Split Between CPUC and FERC... Figure I- Grid Reliability Projects Recorded 00-00/Forecast 0-01 FERC and CPUC Expenditures (Constant and Nominal 00 $000)... Figure I- Double Breaker Line and Bus Configuration... Figure I- Breaker-and-a-Half Line and Bus Configuration... Figure I- Sample Line and Bus Configuration - Before Banks on Breakers Project... Figure I- Sample Line and Bus Configuration - After Banks on Breakers Project... Figure I- Tapped Line Service to Substation B... 1 Figure I- Looped Line Service to Substation B... 1 Figure I- Dual Operating Bus Configuration... 1 Figure I- Renewable Interconnection Projects Recorded 00-00/Forecast 0-01 FERC and CPUC Expenditures (Constant 00 and Nominal $000)... 1 Figure II- Organization Chart... 0 Figure II-1 Transmission/Substation Operations Supervision and Engineering Recorded and Adjusted 00-00/Forecast 0-01 Sub-Account 0.0 (Constant 00 $000)... Figure II-1 Engineering Activities Recorded and Adjusted 00-00/Forecast 0-01 Portion of Sub-Account 0.0 (Constant 00 $000)... Figure II-1 SSID Lab Tools Recorded and Adjusted 00-00/Forecast 0-01 Portion of Sub-Account 0.0 (Constant 00 $000)... Figure II-1 Engineering, Planning and Protection Studies Recorded and Adjusted 00-00/Forecast 0-01 Sub-Account 0.0 (Constant 00 $000)... Figure II-1 Miscellaneous Distribution Expenses Recorded and Adjusted 00-00/Forecast 0-01 Sub-Account.0 (Constant 00 $000)... Figure II-1 Maintenance of Line Transformers SSID Recorded and Adjusted 00-00/Forecast 0-01 Sub-Account.0 (Constant 00 $000)... 0 Figure II-1 SSID Capital Recorded 00-00/Forecast 0-01 (Constant 00 and Nominal $000)... -vi-

8 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management List Of Figures (Continued) Figure Page Figure II-1 Engineering and Project Management Allocated Costs Recorded to Distribution Cost Centers (Constant 00 $000)... Figure II-0 Shop Services and Instrumentation Division Allocated Costs Recorded to Distribution Cost Center D001 (Constant 00 $000)... Figure II-1 Engineering, PMO and Technical Support Groups Employee Counts Historical and Forecasts... Figure II- Shop Services and Instrumentation Division Employee Counts Historical and Forecasts vii-

9 SCE-0 : Transmission and Distribution Business Unit (TDBU) Volume 0, Part - Transmission Interconnection Planning Part - Engineering Design And Project Management List Of Tables Table Page Table I-1 Transmission Interconnection Projects... 1 Table I- CPUC-Jurisdictional Grid Reliability Projects (Constant 00 $000)... Table I- CPUC-Jurisdictional Renewable Interconnection Projects (Constant 00 $000)... 1 Table I- CPUC-Jurisdictional Telecommunications Projects (Constant 00 $000)... Table I- Transmission Interconnection Projects With Less Than $1 Million in CPUC- Jurisdictional Costs (Constant 00 $000)... Table II- Engineering / Others Labor and Non-Labor Combined Recorded 00-00/Forecast 0-01 O&M (Constant 00 $000)... Table II- Miscellaneous Employee Expenses Recorded and Adjusted 00-00/Forecast 0-01 Portion of Sub-Account 0.0 (Constant 00 $000)... Table II- Sub-Account.0 and.0 Forecast (Constant 00 $000) viii-

10 Part Transmission And Interconnection Planning Witness: Patricia Arons

11 SUMMARY The Transmission and Distribution Business Unit (TDBU) plans to spend $. billion in major transmission capital projects between 0 and 01, as shown in the figure below. This chapter discusses the capital projects sponsored by SCE s Transmission and Interconnection Planning (TIP) group with planned operational dates between 0 and 01 and at least $1 million in capital expenditures subject to CPUC jurisdiction. 1 The chapter discusses total project costs for these projects as well as the cost allocation between the CPUC and FERC-jurisdictional rate bases. SCE is requesting only the CPUC jurisdictional costs, which is $. million TDBU Capital Expenditures FERC and CPUC Expenditures ($millions) 1 SCE has several other capital projects sponsored by TIP that have less than $1 million in CPUC-jurisdictional expenditures with planned operational dates between 0 and 01. These projects are discussed generally in section XX below and additional information about these projects are included in the workpapers titled Projects Under $1 Million.

12 A. Introduction And Overview I. TRANSMISSION AND INTERCONNECTION PLANNING Table I-1 below lists the project types, and their associated CPUC-jurisdictional costs, that are discussed in this chapter. Table I-1 Transmission Interconnection Projects 0-01 CPUC-Jurisdictional Capital Expenditures $(000) CPUC Expenditures Project Types Prior Total Grid Reliability Projects $,1 $,1 $,1 $,000 $,000 - $, Renewable Interconnection Projects $1,0 $, $, $1, $ - $, Information Technology-Related Projects $,0 $, $,0 $, - - $,0 Projects Under $1 Million $0 $, $1, $1, $00 - $,1 TIP Project Totals $, $1,0 $,0 $,1 $0,1 - $, B. Transmission Interconnection Projects SCE s high voltage transmission system (00 kv and 0 kv) is the back-bone to SCE s entire electric grid. Having a robust high voltage transmission system is essential for SCE to safely and reliably serve its customers. In order to maintain system reliability, flexibility, and meet our customers future needs, SCE must continue to maintain, expand, and improve the transmission system. The transmission system must be designed to adequately handle the fluctuation in load, generation, and imports and withstand disturbances such as outages, storms, and other events. SCE s high voltage transmission system, which includes transmission lines, substations, and 00/0 kv transformers are under the operational control of the California Independent System Operator (CAISO) and subject to Federal Energy Regulatory Commission (FERC) jurisdiction. With the exception of three subtransmission systems described below, SCE s remaining facilities, collectively referred to as the non-caiso controlled distribution system, are under the operational control of SCE and subject to CPUC jurisdiction. Figure I-1 below illustrates the general jurisdictional split between the CPUC and FERC. 1

13 Figure I-1 General Jurisdictional Split Between CPUC and FERC. Operated by CAISO 00 kv AA AA AA TRANSMISSION 0 kv FERC Jurisdictional A A A CPUC Jurisdictional Operated by SCE kv kv SUBTRANSMISSION B B B B B B DISTRIBUTION The three subtransmission systems which are considered exceptions, and currently under the operational control of the CAISO are: (1) the Devers-Mirage kv System, () the Antelope-Bailey kv System, and () the Victor-Kramer kv System. These subtransmission systems are currently under the CAISO s operational control because they operate in parallel with the CAISO controlled transmission system. However, it should be noted that two of the subtransmission systems, the Devers Mirage kv system in 0 and the Antelope-Bailey kv system in 01, will undergo system reconfigurations and line rearrangements which will result in a change in how these systems operate. The two systems will be reconfigured from parallel systems to radial systems. Thus, they will no longer be operated in parallel with the CAISO-controlled transmission system, resulting in a change in operational jurisdiction from the CAISO to SCE and a change in regulatory jurisdiction from FERC to the CPUC. Generation interconnection activity is conducted according to FERC-jurisdictional tariffs and CPUC rules, depending upon the operational jurisdiction and the business intent of the interconnecting entity. For example, a large generator desiring interconnection to CAISO-controlled facilities would request interconnection from the CAISO and would receive service as required by the CAISO tariff governing that activity. Such a generator could sell its power into the CAISO market or contract with a purchasing entity, either within or outside of the CAISO-controlled area. Alternatively, a small generator with the business intent to bypass electric service and serve on-site load would request service from SCE.

14 according to CPUC Rule 1. Such a generator would be prohibited from selling any of its electrical production beyond the service meter. 1. Project Life Cycle Every proposed project goes through a planning and review process before it is approved and becomes a project. This process assesses several factors, including project cost, sustainability of the project, and environmental impacts of the project. Below are the six phases that a project typically goes through in the project life cycle within the TDBU Organization. Note that project work is also coordinated with other organizations within SCE. 1. Conceptual Phase - A project is in the conceptual phase when the need for a project is identified via an annual program or assessment, a generator interconnection request, or a state mandate. During this phase the proposed project, which often includes several project alternatives, is assessed. Project alternatives are not eliminated from discussion.. Under Development Phase - Once the proposed project or one of the project alternatives is selected for further analysis, a job walk out in the field is conducted and preliminary engineering is performed to determine if the proposed project is feasible and cost-effective. An official project summary detailing the project scope is developed and the project sponsor seeks approval from SCE s internal committees. Preliminary project cost estimates are also developed. At this point, the project is no longer considered a project alternative, but the preferred alternative or simply the proposed project.. Engineering and Design Phase - Once the proposed project has received formal SCE management approval, detailed engineering work such as line routes, transmission tower sizing, and substation layout is performed, the project scope of work is refined, and more detailed cost estimates are developed.. Licensing Phase - During the licensing phase, work is performed to prepare and apply for any required permits from the CPUC, such as the Permit to Construct (PTC), Certificate of Public Convenience and Necessity (CPCN), Proponent s Environmental Assessment (PEA) and others.. Construction Phase - During the construction phase, final engineering, design and procurement activities are underway. Equipment has arrived and construction and testing is taking place.

15 Operational Phase - Project is energized and is operational.. Projects Discussed In This Chapter Projects discussed in this chapter fall into four major categories: (1) projects needed to support grid reliability, () projects needed to interconnect generation, including renewable energy, to SCE s transmission system, () 0% FERC-jurisdictional projects that have at least $1 million in CPUC jurisdictional information technology expenditures and () projects with less than $1 million in CPUC jurisdictional expenditures. C. Grid Reliability Projects Grid reliability projects, such as those described below, are necessary to provide reliable service to our customers as the demand for electricity increases in our service territory and to provide continuity of service under various system conditions, including abnormal system conditions. Abnormal conditions can include, but are not limited to, planned facility outages for maintenance, unplanned facility outages due to equipment failures, abnormally hot ambient temperatures, and facilities removed from service as a result of a fault occurring on the system. SCE must continue to expand, upgrade, and reinforce the electric system to provide safe and reliable electric service to our customers. Without these improvements to our transmission system, the reliability and safety of SCE s electric grid can potentially degrade, which compromises SCE s ability to adequately serve its customers and can potentially endanger SCE employees and the public. Figure I-, below, provides five years of recorded grid reliability capital expenditures and the total capital expenditures SCE expects to incur for grid reliability projects between 0 and 01.

16 Figure I- Grid Reliability Projects Recorded 00-00/Forecast 0-01 FERC and CPUC Expenditures (Constant and Nominal 00 $000) $00,000 $0,000 $00,000 $0,000 $00,000 $,000 $0,000 $0,000 $ Constant $ Nominal $ Trans Proj - Reliability Nominal $ $0, $1,0 $0, $1, $1,1 00 Constant $ $1,0 $1,1 $, $ $0 00 Constant $ $1, $1,1 $, $0, $1,0 Nominal $ $, $, $0,0 $,1 $,1 Forecast Table I-, below, contains a list of the Grid Reliability projects that have over $1 million in CPUC-jurisdictional capital expenditures and are expected to be completed and operational by the end of 01. Table I- CPUC-Jurisdictional Grid Reliability Projects (Constant 00 $000) PIN Project Operating CPUC Expenditures Date Prior Total 1 Rio Hondo Substatio Circuit Breaker Upgrades 1/1/0,,, ,000 Acton Substation Loop-In /1/0,00, ,00 Victor rd A Bank and Rebuild of kv Switchrack /1/01 1, , East Kern Wind Resource Area 1/1/ ,000,000,000 -,000 Grid Reliability Project Totals,1,1,1,000,000 -,

17 Rio Hondo Substation Circuit Breaker Upgrades SCE will install eight circuit breakers at Rio Hondo Substation. The project is expected to be completed and operational by December 0. SCE forecasts total project expenditures of $1.0 million, including $.0 million of CPUC-jurisdictional expenditures. a) Background Substations are connection points on the electric grid that serve the purpose of redistributing and rebalancing power flowing across the grid. In the same way that a hub can connect the spokes of a wheel, the substation connects lines and transformers and other components of the electric grid. Circuit breakers are individual equipment components that are typically installed in substations and are used to connect the components of the electric grid. The reason why circuit breakers are used to connect electric grid components is that they have the special ability to perform the specific functions of either carrying current or interrupting current, depending on whether normal or abnormal conditions exist on the system. For this reason, two ratings are assigned to circuit breakers, a continuous current rating and a short circuit duty rating. The continuous current rating of a circuit breaker reflects the current carrying capability of the breaker when system conditions are normal. This rating is typically matched to or slightly larger than the capabilities of the equipment to which it is connected, albeit in a line and bus configuration that has complexity associated with how equipment is matched. Line and bus configurations are discussed further below. The short-circuit duty rating of a circuit breaker reflects the current interrupting capability of the breaker. The interrupting capabilities of circuit breakers are relied upon to safely interrupt abnormal current flow at times when faulted conditions exist on the grid (and current flows tend to be higher by factors between to 0 times normal flows). This rating is always higher than the system short circuit duty under faulted conditions. System short circuit duty will change as the electric grid configuration is changed or new equipment is added. The interrupting capabilities of circuit breakers are also relied upon to safely interrupt normal current flow at times when system switching is necessary to reconfigure the electric grid The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Rio Hondo Substation Circuit Breaker Upgrades (Project #1).

18 to roll load or accomplish other operating needs, or, when maintenance is needed on the lines, transformers or other grid equipment to which the breaker is connected. In order to maintain or repair equipment such as lines, transformers, capacitors, or other equipment, the equipment must first be deenergized by opening the appropriate circuit breakers, then safely isolated by opening disconnect switches, and further grounded for the protection of workers by applying personal grounds. In the same way that adding more spokes to a wheel creates a stronger wheel, adding more components and connections to an electric grid creates a stronger grid capable of delivering more current under both normal and abnormal conditions. Undersized circuit breakers operating under normal conditions can cause thermal overload failures of the circuit breaker. The thermal overload failure modes of circuit breaks are somewhat unpredictable. The failure can simply stop current flow when the gas density switch trips the breaker, or, a catastrophic failure can occur with more problematic consequences within the substation. However, inadequately sized circuit breakers under abnormal (faulted) conditions are dangerous because current can continue to flow when it should be interrupted, potentially leading to a catastrophic failure of the breaker in addition to other problems at the fault site that occur when current is flowing where it is not intended to flow. Properly sized circuit breakers are important not only to protect the individual large components of the electric grid from damage under abnormal conditions, but also for the reliability of electric service to our customers and the safety of our employees and the public. As discussed above, substations are connection points on the electric grid that serve the purpose of redistributing and rebalancing power flowing across the grid, by connecting lines, transformers and other components of the electric grid to each other. The actual connections within the substations are accomplished in a physical arrangement referred to as a line and bus arrangement. The line and bus arrangements within a substation follow certain time-worn principles intended to assure that the components of the electric grid can be operated in a safe and reliable manner, while providing both operational flexibility, maintainability and to some limited degree, redundancy of critical components, depending upon the actual arrangement of concern. Because substations commonly contain multiple voltage levels, a substation is often referenced using only the highest voltage within the substation, even though there are lower voltages at the same location. SCE commonly uses two types of arrangements for higher voltages. The first type of line and bus arrangement is shown in Figure I-, and is typically used for 00 kv voltage levels. This arrangement is called a double-breaker configuration. In a double-breaker arrangement, two circuit breakers are used to connect a single line or other grid element to the substation bus. Usually, there are

19 two buses for a given voltage within a substation and breakers and lines and other elements are connected between each bus in numbered positions in groups of three breakers or two breakers depending on the breaker arrangement. The grid elements are described as being terminated, or connected in an equipped position. Figure I- Double Breaker Line and Bus Configuration Line 1 Generation Position #: 1 North Bus Disconnect Breaker South Bus Transformer Bank Load Line The second type of line and bus arrangement is shown in Figure I-, and is typically used for 0 kv and kv voltage levels. This arrangement is called a breaker-and-a-half configuration. In a breaker-and-a-half arrangement, three circuit breakers are used to connect two lines to the substation bus (hence breakers per lines equals 1. breakers per line).

20 Figure I- Breaker-and-a-Half Line and Bus Configuration Load Generation Line Line Transformer Bank Position #: 1 North Bus Disconnect Breaker South Bus Line 1 Line Line Load Over the years, different connection methods have been utilized that vary from the typical double-breaker or breaker-and-a-half configurations. In some cases, a substation voltage level can contain a mix of configurations with one position equipped for double-breaker configuration while another position is equipped for breaker-and-a-half configuration. Typically, this occurs at a 0 kv station that has not yet reached its ultimate design capacity. Therefore, a position equipped with two breakers in a double-breaker configuration would have a space provision in the substation for adding a third breaker and creating a breaker-and-a-half configuration for the position, thus accommodating a new line termination with the addition of one breaker. This expansion flexibility is typical of 0 kv stations that have not yet reached their ultimate design capacity. An additional variation to termination of a grid element in an equipped position occurs when a capacitor or transformer or other equipment is connected directly to the substation bus using no breaker or possibly a single breaker. An example can be seen below in Figure I-. At Rio Hondo Substation, all four of the 0/ kv transformers were connected directly to the buses without breakers. However, bus tie breakers were inserted in the middle of each bus as a means of separating each transformer such that a bus outage would not result in loss of half of the

21 station transformation capacity. The reasons for this arrangement go back a number of years where it appears that past practice led SCE to utilize fewer breakers per element. At Rio Hondo Substation, the effective breaker per element ratio for the transformer connections would have been approximately two breakers (counting only the two bus tie breakers) per four transformers or a configuration of approximately half-a-breaker. Figure I- Sample Line and Bus Configuration - Before Banks on Breakers Project Line Line Line NORTH 0 KV BUS 1 M CAP BK CAP BK SOUTH 0 KV BUS Line 1 NO. A BK NO. A BK NORTH SOUTH NO. 1A BK SOUTH NORTH NO. A BK LEGEND M Existing Motor Operated Disconnect Today, SCE recognizes the difficulties of managing operations and maintenance with this practice, especially at higher load levels compared with past years. Back-up clearing of a fault is a situation where a primary breaker fails to open, necessitating a number of breakers to open which can result in removal of large sections of a substation from operation, which is a situation that can significantly reduce reliability. Therefore, as part of a system wide effort to improve reliability and restore operational flexibility and maintainability, SCE proposed a project for all 0/ kv transformers that are currently connected directly to the bus as described above to connect into either a double-breaker or breaker-and-a-half position, as appropriate. Figure I- shows an example configuration with transformers terminated in positions that are equipped with two breakers.

22 Figure I- Sample Line and Bus Configuration - After Banks on Breakers Project Line Line Line NORTH 0 KV BUS 1 M SOUTH 0 KV BUS Line 1 NO. A BK NO. A BK NORTH SOUTH NO. 1A BK NO. A BK LEGEND M Existing Motor Operated Disconnect 1 b) Project Scope The scope of the project includes installing eight- kv circuit breakers at Rio Hondo kv Substation with high capacity circuit breakers. Because system short duties overall are slowly increasing over time, the new breakers being installed will be capable of interrupting 0 ka of short circuit duty.. Acton Substation Loop-in Project The Acton Substation Loop-in Project will provide two line service to Acton Substation by looping in the existing Acton-Palmdale-Ritter Ranch-Shuttle kv line. The project is expected to be completed and operational by June 0. SCE forecasts total project expenditures of $. million, all of which is CPUC jurisdictional. The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Acton Substation Loop - In (Project #).

23 a) Background Subtransmission lines serve B-station substations that step voltages down from kv to 1 kv. There are many varied subtransmission line arrangements that are possible when connecting B-station substations. The requirements for the type of line arrangement that can be utilized depend upon the amount of power being carried, the line loading capability, voltage drops and contingency line loading requirements, the ability of automatic protection schemes to be able detect faults, and the remote automation needs associated with operations. In any particular geographic area, where small customer loads are dispersed over a relatively large geographic distance, a line might have several taps serving B-stations. In another geographic area, where load is very dense, there may be few load taps, with most stations served with two-line service. In general, the more taps on a line, the more complex the protection requirements become to properly detect the difference between normal currents serving load and abnormal currents that must be interrupted under faulted conditions. When B-station loads approach MWs, it is appropriate to consider two-line service for reliability purposes. Two-line service to a B-station provides greater reliability because when one line is out of service, the remaining line can provide continuous uninterrupted service to the customers served from the B-station. Alternatively, when a B-station is served from a single tapped line, whenever that line is out, electric service to customers served from that B-station will be interrupted until service can be restored. At kv, with a fully loaded line, this distance would be limited to around 1 miles, but could be longer if the line is not fully loaded. 1

24 Figure I- Tapped Line Service to Substation B Line Tap Line Substation A Line Substation C Substation B 1 Changing tapped service to two-line service for a B-station requires construction of a loop. For example, suppose substation B is served from a tapped line between substation A and substation C, as shown above in Figure I-. The name of the line is always in alphabetical order, irrespective of which substation is served by the tap. So, the name of the tapped line in this case is the A- B-C line. Figure I- Looped Line Service to Substation B Line Line Substation A Substation C Substation B Forming looped service to Substation B, as shown above in Figure I-, would result in two lines serving substation B. So, the lines formed would be the A-B line, and, the B-C line. The line construction required would be basically the length of the original tap portion of the line that goes to substation B. In general, the tap portions of lines tend to be relatively short in comparison to main 1

25 line itself, between substation A and substation C. The main expense of accomplishing looped or two line service is usually related to the additional substation breakers, positions, protection and communication equipment that would be required at substation B, in this example, to terminate the second line. Through the Annual Transmission Expansion Plan Studies submitted to the CAISO, SCE identified the need to improve the reliability of service to Acton Substation. The Acton kv Substation is currently served by single line service via a tap on the Acton-Ritter Ranch-Palmdale- Shuttle line. Note that the name of line, in this instance, is comprised of four substation names. This is because there are two substations served via taps on the main line; Acton and Shuttle. The difference between Acton and Shuttle is that Shuttle has two-line service from a second line tap, while Acton is served with only one line. SCE proposes to provide two line service to Acton Substation by constructing a new kv line that is 00 feet in length from the existing Acton-Ritter Ranch-Palmdale-Shuttle line to form the Acton-Ritter Ranch kv line and Acton-Palmdale- Shuttle line. This project will improve the reliability of service to Acton Substation because the construction of a second line will assure that electric service to customers served from Acton Substation will no longer be interrupted when one line is out. The telecommunication scope will include installation of various communication equipment at Acton, Anaverde, Shuttle, Palmdale, and Vincent Substations. Installation of this equipment will enable high speed protection, remote control and automation which will further improve operations. b) Project Scope Major components of the project include construction of a kv switchrack at Acton Substation, construction of 00 feet of new kv line in order to loop-in the existing Acton-Ritter Ranch-Palmdale-Shuttle kv line into Acton Substation, and form the Acton-Ritter Ranch kv line and the Acton-Palmdale-Shuttle kv line.. Victor rd A Bank and Rebuild of kv Switchrack The Victor rd A-bank and Rebuild of the kv Switchrack Project will increase capacity at Victor Substation in order to meet growing customer demand for electricity and to reconfigure the kv switchrack. This project was approved by the CAISO in 00. Construction for Phase 1 is 1

26 underway and is expected to be completed by June 0. Phase of the project has a scheduled operating date of June 01. SCE forecasts total project expenditures of $. million, including $. million of CPUC-jurisdictional expenditures. a) Background Transformer banks are the largest single piece of equipment in substations. Their functional purpose is to change or transform voltage. In some cases it is desired to increase voltage in order to efficiently ship large quantities of power over very long distances (hundreds of miles). In other cases, it is desired to reduce voltage in order to safely deliver power to customers at household voltage levels. A transformer bank is the equipment that is used throughout the electric grid to change the voltage of the grid in order to accomplish these and various other electric utility operating functions. In general, the larger the voltages that must be transformed the bigger the transformer bank. The very largest transformers on the Edison electric grid are capable of changing the voltage of more than one thousand MW of power. Such sizes of transformer equipment is often taller than a two-story home, but with a smaller footprint and serve thousands of customers. The smaller the voltages that must be transformed, the smaller the transformer bank. The very smallest transformers on the Edison electric grid are capable to changing the voltage of - kva, or, less than 0.1 MW. Such sizes of transformers can be seen atop wooden power poles and function to serve a few customers, such as adjacent homes. Transformers can be the largest single piece of equipment in a substation, and at the same time they are often the most expensive equipment (without power electronics controls) with the longest lead time for procurement. The reasons for the expense and lead time become evident by examining inside of the transformer. The biggest transformers involve complex construction designs that wrap insulated conductive windings around a ferromagnetic core (laminated steel core) in a complex pattern that directs magnetic flux, induces currents in secondary windings and results in transforming the voltage of the currents fed into the unit. All the while, mechanically braced and compressed to withstand the vibrational forces caused by alternating currents that threaten to tear the unit apart. The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Victor rd A Bank and Rebuild of kv Switchrack (Project #). 1

27 The particular bank that will be installed at Victor Substation will be filled with, gallons of oil to provide electrical insulation and facilitate the distribution and dissipation of the heat that would otherwise break down insulating materials. The unit is extremely heavy ( tons) in its undressed state (not yet filled with oil, absent the radiators used for cooling and absent the bushings that will eventually sit atop the unit for connection to the grid) and it is very difficult to move. Any small bump or jar can affect the integrity of the internal workings of the unit. Moving such large equipment is often done slowly (at road speeds that might not exceed mph), at night, with special heavy moving equipment, accompanied by a contingent of movers, engineers, police, and other concerned officials. The very nature of a transformer bank, which includes its cost, procurement lead times and unwieldiness in moving, necessitate very careful consideration of how the unit will be utilized and to what degree the unit can bear any overload conditions. Because loading, especially overloading can have a direct bearing on the potential loss of life of the unit, overloads, while allowable under emergency conditions are very undesirable. Factors, such as the unit s ability to dissipate heat are considered when assessing the allowable long term emergency loading limits. Of particular concern is the loading condition the unit will be subject to when another transformer at the same location fails. As stated earlier, the long lead time to replace a failed unit will require the remaining operating transformer to endure potentially heavy loading (with the attendant heating) on a potentially repetitive cyclical basis until the failed unit is replaced. This can be a year or more. The risk is that improper decisions when setting loading limits can lead to additional unit failures, which can greatly diminish substation transformer capacity which will directly jeopardize reliability. Victor Substation has two 0/ kv transformer banks, numbered as Bank No.1 and Bank No., which transform voltages from 0 kv to kv. Because customer load in the area has grown, either Bank No. 1 or Bank No. will be overloaded beyond its allowable long term emergency loading limits should either bank fail for any reason. In addition, the existing kv switchrack configuration is obsolete and must be rebuilt in order provide a proper level of reliability. The term switchrack collectively refers to the line and bus configuration and equipment for the for the kv voltage level. This particular rack dates back to 10 when it was originally built by the California Electric Utility Company. The existing switchrack configuration is a dual operating bus arrangement, which is no longer appropriate for the Victor Substation, given the size of the load served out of the station and the number of lines coming into and out of the switchrack. The configuration is considered a dual operating bus configuration, because of the simultaneous use of both buses to connect operational grid elements. There are three aspects of the 1

28 existing switchrack that make it no longer viable as a line and bus arrangement: (1) termination of the new 0/ kv transformer; () back-up protection clearing; and () reliability. First, as can be seen on Figure I-, all grid elements are directly connected to either one of the two buses via a single breaker, and there is only a single breaker connecting the two buses. There are two source transformers, each connected to a bus. This leaves no place for termination of the new third transformer. Because the scheme has one breaker per element, in the event of a line or grid element fault followed by a breaker failure, the bus to which the failed breaker is connected must be stripped, meaning all breakers connected to the bus must open. Interruption of power flow to multiple elements in this fashion jeopardizes the overall reliability of service to customers through service interruptions and outage durations. Figure I- Dual Operating Bus Configuration 0 kv Source 0 kv Source Line Line kv Bus 1 kv Bus Line Line Given that there is no appropriate place to connect a third transformer in the operating and transfer bus configuration, the third bank must be connected to either of the existing two buses. The consequence of a breaker failure is loss of two thirds of the station transformer capacity, because, as stated above, this configuration is subject to stripping the bus under back-up clearing conditions. With loss of two banks, the momentary loading on the third bank becomes tripled, which potentially jeopardizes the integrity of the third bank. 1

29 Because of the various operational and protection problems associated with an operating and transfer bus arrangement, it is necessary to rebuild the switchrack to be able to accommodate a breaker-and-a-half configuration and connect the third transformer bank. There is insufficient physical space between the two existing kv buses to be able to accommodate the three breakers needed for a breaker-and-a-half configuration. Given the age and lack of space, the existing kv switchrack must be removed, then rebuilt on a larger footprint, so that sufficient space is available to place the breakers in the new configuration. b) Project Scope This project is required to meet future load demand at Victor Substation. In addition to the installation of the rd A-bank for load growth, the project includes installation of the th A- bank for continuity of service to load during construction. Because three banks are required to be in service at all times, a fourth bank was added so that during times when a bank was disconnected as construction proceeded, load service would not be jeopardized. The project also includes the teardown of the existing switchrack and construction of a new breaker and a half configuration kv switchrack. Phase 1 of the project includes teardown and rebuild of approximately half of the kv switchrack, installation of two new 0/ kv banks, and relocation of six subtransmission lines into the new portion of the switchrack. Phase includes the remainder of the kv switchrack rebuild as well as relocation of remaining elements into the new switchrack. At the completion of the kv switchrack rebuild the th A-bank will become an energized spare for the station and remain in its location in the station as well as in the switchrack. Because the existing Mechanical Electrical Equipment Room (MEER) is full and additional relays and other equipment are needed for the breakers associated with the new switchrack, a new MEER will need to be constructed. The telecommunication scope of work for this project includes the necessary interception of the existing communication circuits and connecting them into the new MEER.. East Kern Wind Resource Area (EKWRA) The EKWRA kv Reconfiguration Project will separate the existing Antelope-Bailey kv subtransmission system into two systems. The EKWRA Project was approved by the CAISO in 1

30 March 0. The project is expected to be completed and in-operation in December 01. SCE forecasts total project expenditures of $.0 million, all of which are CPUC jurisdictional. a) Background The EKWRA includes both SCE customers as well as numerous wind generation projects. This area also includes the approximate geographic area between the towns of Tehachapi to the town of Mojave. The electric system serving this general area today is part of the CAISO controlled Antelope-Bailey kv system. The Antelope-Bailey kv system has experienced operational, and reliability challenges caused by growing load in the southern portion of the system and the increasing production capability of existing renewable resources in the northern portion of this system. As part of its efforts to help California reach its state mandated Renewable Portfolio Standard (RPS) goal, SCE developed the Tehachapi Renewable Transmission Project. The Phase I facilities (Segments 1-) of this project have already gone into operation. The EKWRA project will make use of the new Windhub Substation built as part of Segment. Windhub Substation will provide a source for a new radial kv network that will serve both load and generation in the Tehachapi to Mojave area. The new radial network will be created by a reconfiguration of the existing Antelope- Bailey kv network and construction of approximately miles of new kv lines. By reconfiguring the Antelope-Bailey kv System, those kv lines that today operate in parallel with the 0 kv lines between the Bailey 0 kv and the Antelope 0 kv Substations, at the conclusion of the EKWRA Project will no longer operate in parallel with any 0 kv lines. This new radial configuration will address the following reliability problems: line and transformer thermal overloads, dynamic and voltage instabilities in the northern system, line congestion and the new configuration will resolve line loading problems by eliminating the north-to-south flow issue. This project will provide a more reliable system with lower voltage deviations during outages. b) Project Scope The EKWRA kv Reconfiguration Project will separate the existing Antelope- Bailey kv system into two systems: the EKWRA kv system and the Antelope-Bailey kv system. Consistent with the system design philosophy illustrated above in Figure I-, the reconfigured The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled East Kern Wind Resource Area (EKWRA) (Project #). 1

31 electric system serving customers and generators in the EKWRA will be served radially from SCE s new Windhub Substation and as such will not be under CAISO control. The reconfigured Antelope-Bailey kv electric system that serves the general area of the city of Lancaster and Palmdale will remain parallel to the 0 kv system at Antelope and Bailey Substations and will retain the label of the Antelope-Bailey kv system. The north-to-south lines that once connected EKWRA to the Antelope-Bailey kv system will be opened. The project will segregate the EKWRA northern system from the Antelope-Bailey kv System and connect it to the Windhub substation. Windhub Substation will be a new source bus located directly in the middle of the northern system. Finally, the Antelope-Bailey kv System is in parallel with the 0 kv system at Antelope and Bailey Substations through a single kv line. By virtue of opening a single kv breaker at Neenach Substation, the final step to create two radial kv systems from Antelope and from Bailey 0 kv Substations can be accomplished. This last step will be taken when operationally convenient and necessary, however, it is expected within the time horizon of this rate case. When this step occurs, it is expected that the two new radial kv systems would no longer be under the CAISO s operational authority, nor would the facilities remain under FERC jurisdiction. Instead, they would move into SCE operational authority and would become CPUC-jurisdictional. Since Acton kv Substation is served from the Antelope 0 kv Substation, the Acton Loop-in Project described earlier in this testimony is expected to be 0% CPUC jurisdictional at the same time. D. Renewable Interconnection Projects SCE is obligated under the Federal Power Act and the CAISO Tariff to interconnect and integrate wind generation facilities. The CPUC Board of Commissioners, which governs Investor-Owned Utilities (IOUs), such as SCE, has as its stated objective: to facilitate the construction of transmission facilities that will advance California s Renewable Portfolio Standard (RPS) goal of a 0-percent level of attainment in meeting total energy deliveries by 0. The Tehachapi Renewable Transmission Project represents one of the SCE s methods to accomplish the following three goals. The first goal is to interconnect and integrate privately-developed wind energy generators located in the Antelope Valley and Tehachapi areas of north Los Angeles and south Kern County, collectively referred as the Tehachapi Wind Resource Area (TWRA), into the SCE electrical grid. The second goal is to enable California utilities to comply with the state mandated RPS goals by providing improved access to renewable resources in the Tehachapi Wind. The third goal is to address the load serving reliability needs of the CAISO controlled grid due to projected load growth in the 0

32 Antelope Valley as well as projected South of Lugo power transfer increases associated with load growth in Southern California. Figure I-, below, provides five years of recorded renewable interconnection project capital expenditures and the total capital expenditures SCE expects to incur for renewable interconnection projects between 0 and 01. Table I-, below, contains a list of the renewable interconnection projects that have over $1 million in CPUC-jurisdictional capital expenditures and are expected to be completed and operational by the end of 01. Figure I- Renewable Interconnection Projects Recorded 00-00/Forecast 0-01 FERC and CPUC Expenditures (Constant 00 and Nominal $000) $00,000 $00,000 $00,000 $00,000 $00,000 $00,000 $00,000 $00,000 $0,000 $ Constant $ Nominal $ Trans Proj - Renewable Nominal $ $0 $ $, $,1 $, 00 Constant $ $0 $1 $, $ $0 00 Constant $ $1, $1,00 $1,0 $,1 $, Nominal $ $, $,00 $, $, $0 Forecast Table I- CPUC-Jurisdictional Renewable Interconnection Projects (Constant 00 $000) PIN Project Operatin CPUC Expenditures g Prior Total Tehachapi Renewable Transmission - Segment /1/01, 0-1, Tehachapi Renewable Transmission - Segment /1/01 0 1,,1 1 -,0 1 El Dorado-Ivanpah Transmission Upgrades /1/ , -, Renewable Interconnection Project Totals 1,0,, 1, -, 1

33 Tehachapi Renewable Transmission Project (TRTP) Seg. and Seg. TRTP Segment consists of the Vincent-Mira Loma 00 kv Transmission Line between Vincent and the Mesa Area. Segment consists of the Vincent-Mira Loma 00 kv Transmission Line between Mesa and Mira Loma Areas. Segment was approved by the CAISO in 00 and has a scheduled in-service date of March 01. For Segment, SCE forecasts total project expenditures of $.1 million, including $1. million of CPUC-jurisdictional expenditures. Segment was approved by the CAISO in 00 and has a scheduled in-service date of March 01. For Segment, SCE forecasts total project expenditures of $. million, including $.0 million of CPUC-jurisdictional expenditures. a) Background The Tehachapi Renewable Transmission Project supports the intent of Senate Bill which established a program requiring IOUs to have 0 percent of the energy used produced by renewable generation sources, such as biomass, geothermal, small hydro, solar, and wind by the year 01. Specific to SCE, the project would increase SCE s ability to deliver additional renewable energy from the TWRA to its load centers in the greater Los Angeles basin and in the rapidly growing portions of both western Riverside and San Bernardino Counties. This project will help improve system reliability and increase operational flexibility. Without this work, SCE will jeopardize the reliability and safety of its electric grid, and compromise its ability to serve its customers. b) Segment Project Scope The Vincent-Mira Loma 00 kv transmission line section between Vincent and the Mesa area will be completed by replacing the Vincent-Rio Hondo No. 0 kv transmission line with 00 kv construction, and upgrading existing transmission near Vincent and between the City of Duarte and the Mesa area. The upgrades near Vincent involve removing five miles of the Vincent-Rio Hondo No. 0 kv single circuit transmission line between Vincent and the Angeles National Forest and replacing it with a new five mile 00 kv single circuit transmission line. The upgrades between the City The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony entitled TRTP SEG (Project #). The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony entitled TRTP SEG (Project #).

34 of Duarte and the Mesa area involve removal of the remaining section of existing Antelope-Mesa 0 kv and replacing it with approximately 1 miles of new double-circuit 00 kv transmission line section. In addition, in order to maximize the use of the existing transmission right-of-way, several kv lines between the Rio Hondo and Mesa areas need to be relocated to either new right-of-way or SCE franchise. It should be noted that the use of double-circuit 00 kv design specifications for the new construction is prudent and recommended to maximize capability of limited transmission corridors. This will also minimize environmental impacts and avoid significant waste associated with multiple tear-down and rebuild construction activities. The use of double circuit 00 kv construction standards will also allow for a future low cost upgrade of a second 00 kv transmission line when required to further increase deliveries of renewable energy from Tehachapi and the North of Lugo areas to the Los Angeles Basin. Segment also includes a telecommunication portion that involves the extension of Optic Ground Wire (OPGW) into the communication room at Rio Hondo Substation, and the installation of associated multiplexers and equipment, copper and fiber optic cables in underground ducts when kv lines are rerouted, and fiber wrap optic cables. c) Segment Project Scope The remaining portion of Vincent-Mira Loma 00 kv transmission line between the Mesa area and Mira Loma will be double-circuit 00 kv mostly located in existing SCE transmission line right-of-way. In order to utilize the existing right-of-way, 0 kv transmission consolidations will be required. These consolidations include the removal of an existing 0 kv idled transmission line segment, the removal of an existing 0 kv single-circuit line and replacement with new 0 kv doublecircuit line, and the relocation of several kv lines in the Chino area. Although not part of this plan, SCE is developing a conceptual project for a new Mesa 00 kv Substation and a possible future 00 kv transmission line between Mesa and Serrano Substations. This can only be accomplished with the use of double-circuit 00 kv design specification for the new construction making such a design prudent and necessary to maximize the capability of limited transmission corridors. The use of double-circuit 00 kv transmission line design specifications will also minimize environmental impacts and avoid significant waste associated with multiple tear-down and rebuild construction activities. Such future upgrades will be necessary to further increase deliveries of renewable energy from Tehachapi and the North of Lugo areas to the Los Angeles Basin at an unknown future point in time. The telecommunication scope of work for Segment includes the installation of fiber optic cables to bypass the Chino Walnut fiber Optic Ground Wire (OPGW) cable, which is constructed on a portion of the Mesa Chino 0 kv transmission line, which will be demolished.

35 Installation of associated multiplexers and equipment at various locations, telecommunications equipment in the new communications room at Mira Loma Substation, copper and fiver optic cables in underground ducts where kv lines are rerouted.. Eldorado Ivanpah Transmission Upgrades a) Background The Eldorado Ivanpah Transmission Upgrades project is needed in order to: 1) comply with the state-mandated RPS, and ) integrate planned renewable generation resources from the Ivanpah Dry Lake Area. The project is expected to be completed and in-operation in July 01. SCE forecasts total project expenditures of $. million, including $. million of CPUC-jurisdictional expenditures. SCE s existing transmission facilities in the area will not be able to provide the transmission capacity needed for the projected solar generation development. The Eldorado-Ivanpah Transmission Project will provide the electrical facilities and capacity necessary to access and deliver power from renewable resources. It will also enable Nevada to export clean energy to California. The Eldorado Ivanapah Upgades Project also supports state and federal renewable energy goals and supports the reduction of greenhouse gas emission b) Project Scope This scope of this project includes: (1) constructing a new 0/ kv Ivanpah substation near Primm, Nevada, () replacing of a portion of an existing kv line with a -mile double-circuit 0 kv transmission line, () connecting the new Ivanpah Substation to SCE s Eldorado Substation near Boulder City, Nevada, () upgrades at Eldorado Substation to support the connection of new transmission lines, and () constructing two separate telecommunications pathways and communication equipment to connect the project to SCE s existing telecommunications system. E. Additional Projects Included Strictly For Their Telecommunication Costs The following projects, shown in Table I-, below, have 0% of their TDBU-related costs under FERC jurisdiction, but have a telecommunication component over $1 million that is CPUC jurisdictional. The total project costs are included in the figures above in the transmission interconnection and renewable The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Eldorado Ivanpah Transmission Upgrades (Project #1).

36 interconnection sections above. This section includes only the telecommunication portion of these projects. These projects will be discussed in brief, with a more detailed description of the telecommunication scope of work. There are four primary reasons for installing telecommunication equipment; 1) monitoring to provide operators with equipment loading information and system conditions as well as communications for operator to operator coordination, ) communications for protection under abnormal conditions ( i.e. fault clearing), ) Special Protection Systems (SPS) to trip load or generation for mitigation purposes, and ) remote control access for opening and closing protective devices (including circuit breakers) for maintenance and other operations requirements. Communications for system condition monitoring and equipment loading allows data to be gathered and recorded related to voltage, frequency, customer loads and other network data to support operations planning and design as well as to support post disturbance analysis that are needed to develop corrective and preventive mitigations. Communication also allows measurement and detection of adverse conditions on the electric grid and enables isolation and segregation of portions of the grid directly affected by an adverse event. Communications also allow automatic transmittal of signals to clear the adverse conditions. For example, communications enable high speed fault detection by measuring and comparing current direction at each end of a line, determining the exact location of a fault and thereby transmit a signal to open the appropriate breakers on both ends to isolate the faulted line. Other adverse conditions include thermal overloads, low voltages, or system instability. In some instances the mitigating actions must be very rapid to prevent damage or cascading of the disturbance to a wider area. With the necessary protective equipment and the communications infrastructure, the condition may be cleared automatically or manually, depending on the severity of the situation and the allowable time for the corrective action. Prior to 10 s all SCE transmission and major distribution substations were manned. An operator was present at all times to watch over substation equipment. The operator would physically sit in front of a set of meters and monitor equipment loading levels and recording data. Although protective trips were automatic for fault clearing, all switching and line clearing was done manually at each substation. Prior to the 10 s, communications circuits consisted of pilot wire or telephone wire on subtransmission lines and power line carrier on transmission lines. Until the 10 s, analog audio tone communications were entirely over copper wires, when we began to implement microwave technology and utilize digitally coded signals, bringing speed and reliability.

37 SCE continued to deploy analog audio tone technologies for mainly lower voltage facilities until the 10 s, when we began to evolve into an all-digital network. Prior to that time, we used a different type of analog multiplexing technology with our pre-digital microwave signal transmission network. Once fiber optic technology was adopted and implemented it significantly improved the volume and reliability of the communications signal processing. Signal loss was a problem on wires-based communication circuits, which limited the geographic distances that could be covered with protection schemes. Signal transmission impairments were sometimes an issue with analog microwave communications and bandwidth was always a significant limitation with this technology. Fiber optics enabled very reliable, high volume, and high bandwidth speed-of-light signals to remote control access to equipment at distant substations, enabling implementation of sophisticated protection technologies and unmanning of substations. Various telecommunication equipment is used in SCE s communication network that fulfills the purpose above. Understanding the functionality of each component may facilitate an understanding of how a communication network functions, the real purpose of the communication network is described above for each of the following projects. Multiplexors for example enable more communications channels to be packed into a fiber cable. Lightwave devices are electronics devices that essentially produce the bursts of light that travel down a fiber. Depending how the light is digitally encoded, additional channel equipment might be needed to encode or decode the signal and direct it to an appropriate destination. Optical power ground wires are essentially conductors used for ground wire protection, but packed with fiber for communications. All of the hierarchical building block elements function together to achieve the purposes described above which are; 1) monitoring to provide operators with equipment loading information and system conditions as well as communications for operator to operator coordination; ) communications for protection under abnormal conditions (i.e. fault clearing); ) Special Protection Systems (SPS) to trip load or generation for mitigation purposes; and ) remote control access for opening and closing protective devices (including circuit breakers) for maintenance and other operations requirements.

38 Table I- CPUC-Jurisdictional Telecommunications Projects (Constant 00 $000) PIN Project Types Operating CPUC Expenditures Date Prior Total Devers-Colorado River /1/01 $ $1,000 $,00 $, - - $1, Tehachapi Renewable Transmission - Segment 1/1/01 $00 $, $, Tehachapi Renewable Transmission - Segment /1/01 - $, $ $, 0 Tehachapi Renewable Transmission - Segment /1/01 - $,1 $1, $,1 Rector SVC and BC/SJV RAS /1/0 $,1 $ $,0 Coram Energy - Brodie Wind I and II /1/0 - $1,000 $ $1,00 Information Technology Project Totals $,0 $, $,0 $, - - $, Devers - Colorado River (DCR) (formerly Devers Palo Verde No. 00 kv T/L The DCR Project includes building the California portion of the Devers-Palo Verde No. (DPV) transmission project. This project will provide the transmission infrastructure needed for developers to transfer an additional 1,00 megawatts of new renewable and conventional generation from the solar energy rich areas of eastern Riverside County to energy customers in Southern California. The project will assist California in meeting its aggressive renewable energy goals of % by 00. SCE forecasts total telecommunications project expenditures of $1. million, all of which are CPUCjurisdictional. a) Background The project consists of constructing the California portion of DCR, a new mile 00 kv line from the new Colorado River Switchyard to SCE's existing Devers Substation. This project also involves construction of the Devers Valley No. line, a new mile 00 kv transmission paralleling an existing line connecting SCE's Devers Substation to SCE's existing Valley Substation in Romoland California. Also, a construction of other reactive support equipment is needed for voltage support, The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Devers Colorado River (DCRS) (formerly Devers Paloverde No. 00 kv T/L (Project #).

39 including shunt capacitors and a Static VAR System. The CPUC approved SCE s application to build the California portion of the project in November 00. The CPUC s decision is contingent upon approval by the CAISO. The project is expected to be completed and operational by April 01. b) Telecommunications Scope The telecommunications scope of work to support the Devers - Colorado River 00 kv transmission line includes the installation of a new digital microwave path from Chuckwalla Communication Site to Colorado River Switchyard, new fiber optic cable from Colorado River Switchyard to Blythe Service Center, from Colorado River Switchyard to Buck Blvd. (WAPA), from Mirage Substation to the 00kV right of way of the Devers - Colorado River 00 kv T/L, and associated multiplexers and equipment at various locations.. Tehachapi Renewable Transmission Project - Segments,, The Tehachapi Renewable Transmission Project (TRTP) is divided into segments. Segment 1- collectively are referred to as the Antelope Transmission Project. Segments - are referred to as TRTP. This section of the testimony includes Segments,, and, as these particular segments have a telecommunication component of over $1 million dollars. All segments include a series of new and updated electric transmission lines and substations that will deliver electricity from new wind farms in the Tehachapi area to SCE customers and the California transmission grid. TRTP is a vital part of meeting California s renewable energy goals. The CPUC approved project Segments 1 to in March 00 and construction is now underway. Segment of the project is expected to be completed and operational by June 01. For Segment, SCE forecasts total telecommunications project expenditures of $. million, all of which are CPUC-jurisdictional. Segment of the project is expected to be completed and operational by March 01. For Segment, SCE forecasts total telecommunications project expenditures of $.0 million, all of which are CPUC-jurisdictional. 1 Segment is expected to be completed and The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled TRTP SEG (Project #). 1 The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled TRTP SEG (Project #).

40 operational by November 01. For Segment, SCE forecasts total telecommunications project expenditures of $. million, all of which are CPUC-jurisdictional. 1 a) Background Segment () includes the construction of two new substations WindHub 00/0/ kv Substation located west of the Mohave area and HighWind 0/ kv Substation located in the Monolith area, both located in Kern County. Also included is a new.-mile 00 kv single-circuit transmission line between the existing and the new proposed WindHub Substation, and a new.-mile 0 kv single-circuit transmission line between two new proposed substations, WindHub 00/0/ kv and HighWind 0/ kv. Segment of the Project involves the construction of a the new Whirlwind 00 kv Substation, two new 0 kv transmission lines traveling approximately miles over new right-of-way (ROW) from the Drycreekwind Substation (formerly referred to as Cottonwind Substation ) to the proposed Whirlwind Substation. It also includes the construction of a new 00 kv transmission line, initially energized to 0 kv, traveling approximately 1 miles over expanded ROW from the proposed new Whirlwind Substation to the existing Antelope Substation. And lastly, construction of a new 00 kv transmission lines to loop existing Midway-Vincent No kv line in and out of proposed Whirlwind is included. Segment involves the installation of substation equipment and upgrades at Antelope, Vincent, Windhub, and Whirlwind Substations to connect new 0 kv and 00 kv transmission lines and to help maintain proper voltage levels. b) Telecommunications Scope The telecommunication work for Segment can be separated by substation. At Windhub Substation, a new communication room will be constructed with new facility equipment, DC power system, antenna tower, and microwave antennas, microwave terminal equipment, lightwave terminal equipment, synchronization equipment, channel equipment, and data network equipment. The optic ground wire will be extended to the telecommunications room. At Highwind Substation, a new communication room will be constructed with new facility equipment, DC power system, antenna tower, 1 The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled TRTP SEG (Project #0).

41 and microwave antennas, microwave terminal equipment, lightwave terminal equipment, channel equipment, and data network equipment. The optic ground wire will be extended to the telecommunications room. At Antelope Substation, installation will include a new antenna tower, microwave terminal equipment, lightwave terminal equipment, channel equipment, and data network equipment in the communication room that is part of TRTP Segments 1 and. At Oak Peak, SCE will install a new antenna tower, microwave antennas, and microwave terminal equipment. At Moorpark, new channel equipment will be installed. The telecommunication work for Segment can be separated by substation. At Whirlwind Substation, a new communication room will be constructed with new facility equipment, DC power system, antenna tower, and microwave antennas, microwave terminal equipment, lightwave terminal equipment, channel equipment, and data network equipment. The optic ground wire will be extended to the telecommunications room. At Windhub Substation, SCE will install additional lightwave terminal equipment, channel equipment, and data network equipment in the communication room that was constructed as part of TRTP 1- (also known as Antelope Transmission Project 1 ). Also, the optical power ground wire will be extended to the communications room.. Rector SVC and BC/SJV RAS Load growth in the San Joaquin Valley has resulted in system instability at Rector Substation under N-1 (single element outage) and N- (two element outage). Transmission and Interconnection Planning sponsored a project to install a 00 MVAR Static VAR Compensator (SVC), and a Phasor Measurement Unit at Rector Substation, and, modify the existing Big Creek/San Joaquin Valley Remedial Action Scheme (RAS) in 00 and 00, respectfully. a) Telecommunications Scope The entire scope of work for this project has not been completed, and installation of optical power ground wire for the RAS to achieve diversely-routed communication network will be completed in September 0. SCE forecasts total telecommunications project expenditures of $. million, all of which are CPUC jurisdictional. 1 1 The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Rector SVC and BC/SJV RAS (PIN ). 0

42 Coram Energy Brodie Wind I and II Coram Energy, LLC (Coram Energy) applied to the CAISO for the interconnection of 1MW of wind generation each from their Brodie Wind I & II (Projects) generating facilities to the SCE kv Subtransmission System pursuant to Section. of the Large Generator Interconnection Procedures (LGIP) issued under the CAISO Tariff. Each project consists of seventeen (1) MW wind turbine generators ("WTG") with a net generation export of 1MW. Both projects will be interconnected SCE electric system at the new 0kV Windhub Substation bus via a new kv line transformed to 0kV at Windhub. The project is expected to be completed and operational by June 0. SCE forecasts total telecommunications project expenditures of $1. million, all of which are CPUC jurisdictional. 1 a) Telecommunications Scope The telecommunication work related to the interconnection of the Coram Energy Brodie Wind I and II project include: the installation of a lightwave, channel, and associated equipment to support protection and SCADA circuits that are required for renewable generation. This includes the installation of approximately. miles of fiber optic cable and the installation of multiplexers and equipment at Windhub, Brodiewind, and Coramwind. F. Projects With Less Than $1 Million in CPUC-Jurisdictional Costs As can be seen in Table I-, below, SCE has several other Transmission Interconnection projects that have less than $1 million in CPUC-jurisdictional expenditures with planned operational dates between 0 and The project costs are based on engineering estimates of the installed cost necessary to add the specified equipment. See workpaper supporting this testimony titled Coram Energy Brodie Wind I and II (Project #). 1 Forecasts for these projects are included in the workpapers titled Projects Under $1 Million. 1

43 Table I- Transmission Interconnection Projects With Less Than $1 Million in CPUC-Jurisdictional Costs (Constant 00 $000) PIN Project Types Operating CPUC Expenditures Date Prior Total Kramer Circuit Breaker Replacement 1/1/0 $ $ $ San Joaquin Cross Valley Loop /1/ $ $00 0 Wildlife Substation /1/ $00 $00 - $00 1 El Nido Area LCR Mitigation /1/0 $1 $ $1 Del Amo 0 kv Bank Criteria Upgrade 1/1/0 $ $ $0 Tehachapi Renewable Transmission - Segment /1/01 $ - $1 $1 - - $0 Tehachapi Renewable Transmission - Segment /1/ $ $1 - - $ 1 Tehachapi Renewable Transmission - Segment /1/ $ $0 Mohave Switchyard Station Separation /1/0 $1 $ $ Blythe Solar 1 1/1/0 $ $ $0 1 Devers - Coachella Valley Loop-In /1/ $00 $ $00 Solar Photovoltaic Program 1/1/00 - $ $0 Under $1 Million Project Totals $0 $, $1, $1, $00 - $,1

44 Part Engineering Design and Project Management Witness Kenneth Varnell

45 SUMMARY This chapter details the work performed by some of the principal groups in the Engineering and Technical Services (E&TS) organization in SCE s Transmission & Distribution Business Unit (TDBU). It covers the following groups: - Engineering, which is responsible for performing engineering design for medium to large substation and transmission projects; analysis of in-service equipment failure; assessment of new technology prior to installation; and development of engineering standards. - Project Management (PMO), which is responsible for project execution and cost management of grid-related capital projects. - Shop Services & Instrumentation Division (SSID), which is responsible for repair, refurbishment, inspection, testing, calibration, and failure/root cause evaluation of electrical and mechanical equipment. - Customer Interconnections / Methods of Services (CI/MOS), which is responsible for managing the grid interconnection applications and methods of service studies to verify compliance with CAISO and CPUC standards. - Engineering and Technical Services (E&TS) Business Management, which is responsible for resource planning and performance measurement for the E&TS organization. - Special Projects, which is responsible for one-time projects execution and business policy evaluation. In this chapter, we are requesting $. million in Capital expenditures for 0 to 01 and $1.0 million in Operations & Maintenance expenses for 01 test year for the O&M activities performed by the groups mentioned above.

46 Engineering O&M Expenses 01 Forecast (Constant 00 $Million)