generation volume 7, part 2 – hydro capital · 2013. 11. 13. · volume 7, part 2 – hydro...

Application No.: Exhibit No.: SCE-02, Vol. 07, Pt. 2 Witnesses: T. Condit

(U 338-E)

2015 General Rate Case

Generation Volume 7, Part 2 – Hydro Capital

Before the

Public Utilities Commission of the State of California

Rosemead, CaliforniaNovember 2013

SUMMARY

This volume describes the SCE Hydro capital forecast of $438.3 million for years 2013-

2017. The capital is divided into 7 main categories:

FERC Relicensing

Electrical Equipment – transformers, circuit breakers, switchgear

Prime Movers – water driven turbines and generators

Dams and Waterways – reservoirs, tunnels, flumes, pipelines, valves

Structures and Grounds – powerhouse structures, support buildings, roads

Furniture, Tools and Equipment – shorter life equipment such as furniture and

tools

Decommissioning – removal of out of service Hydro projects

The capital forecast for the Hydro categories is as follows for 2013-2017:

FERC Relicensing - $50.6 million

Electrical Equipment – $126.3 million

Prime Movers – $69.0 million

Dams and Waterways – $142.0 million

Structures and Grounds – $41.9 million

Furniture, Tools and Equipment – $1.4 million

Decommissioning – $7.1 million

SCE-02: Generation Volume 7, Part 2 - Hydro Capital

Table Of Contents

Section Page Witness

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I. HYDRO GENERATION – CAPITAL EXPENDITURES PLAN DEVELOPMENT ..............................................................................................1 T. Condit

A. Categories of SCE Hydro Capital ..........................................................1

B. 2013-2017 Hydro Capital Expenditure Estimate ...................................1

C. Recorded Capital Expenditures Compared To Previous GRC Authorized ....................................................................................2

D. Hydro Capital Project Categories ..........................................................3

E. Creation of the GRC Capital Forecast ...................................................4

1. Planning for Capital Expenditures .............................................5

2. Capital Estimating Process ........................................................5

II. FERC LICENSING PROJECTS .......................................................................7

A. FERC Relicensing Process ....................................................................9

1. Alternative Licensing Process (ALP) ......................................10

2. Traditional Licensing Process (TLP) .......................................10

B. Big Creek Relicensing Projects ...........................................................10

1. Background ..............................................................................10

a) Big Creek ALP Projects Relicensing ...........................11

b) Portal Hydroelectric Project Relicensing .....................12

c) Vermilion Valley Hydroelectric Project Relicensing ...................................................................12

d) Licensed Big Creek 4 Project ......................................12

2. Delay of License Issuance .......................................................12

C. Relicensing Cost Forecast ....................................................................13

1. Big Creek Alternative Licensing Procedure ............................14


Table Of Contents (Continued)


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a) Implementation of New License Order Terms and Conditions ..................................................14

b) Aquatic Resources .......................................................15

c) Recreational Resources ................................................17

d) Terrestrial Resources Measures ...................................17

e) Land Management .......................................................18

f) Cultural Resources .......................................................18

2. Vermilion Valley Relicensing ..................................................19

3. Big Creek No. 4 Relicensing ...................................................20

4. Portal Relicensing ....................................................................21

III. ELECTRICAL EQUIPMENT .........................................................................22

A. Infrastructure Replacements ................................................................22

1. Eastern Hydro Substation Infrastructure Projects ....................23

a) Background ..................................................................23

b) Projects Scope ..............................................................25

c) Projects Justification and Benefit.................................25

2. Northern Hydro Substation Infrastructure Projects .................26

a) Background ..................................................................26

b) Projects Scope ..............................................................26

c) Project Justification and Benefit ..................................27

B. Region Automation Projects ................................................................27

1. Background ..............................................................................28

2. Projects Scope ..........................................................................28




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3. Project Justification and Benefit ..............................................29

C. Transformer Replacements ..................................................................29

1. Background ..............................................................................29

2. Projects Scope ..........................................................................30


D. Branch Circuit, Control, and Relay Panels ..........................................30

1. Background ..............................................................................31

2. Projects Scope ..........................................................................32


E. Circuit Protection Equipment ..............................................................33

1. Background ..............................................................................33

2. Projects Scope ..........................................................................33


F. Major Electrical Projects ......................................................................34

1. Background ..............................................................................34

2. Projects Scope ..........................................................................35

3. Projects Justification and Benefit.............................................36

G. Electrical Equipment – Miscellaneous Projects ...................................36

1. Background ..............................................................................37

2. Project Scope ...........................................................................37


IV. PRIME MOVERS ............................................................................................39

A. Turbine Wicket Gates, Runners, and Repowers ..................................39




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1. Background ..............................................................................40

2. Project Scope ...........................................................................40


B. Generator Coils and Rewinds ..............................................................41

1. Background ..............................................................................41

2. Project Scope ...........................................................................42


C. Generator Excitation Projects ..............................................................42

1. Background ..............................................................................43

2. Projects Scope ..........................................................................43


D. Turbine Valves and High Pressure Piping ...........................................44

1. Background ..............................................................................45

2. Project Scope ...........................................................................45


E. Prime Mover Replacements .................................................................46

1. Background ..............................................................................47

2. Project Scope ...........................................................................47


F. Prime Movers – Miscellaneous Projects ..............................................48

1. Background ..............................................................................48

2. Project Scope ...........................................................................49





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V. DAMS AND WATERWAYS .........................................................................50

A. Gates and Valves Projects ....................................................................50

1. Background ..............................................................................51

2. Projects Scope ..........................................................................52


B. Structures Improvements .....................................................................53

1. Background ..............................................................................53

2. Projects Scope ..........................................................................54


C. Dam Surface Protection and Seismic Refurbishment ..........................54

1. Background ..............................................................................55

2. Projects Scope ..........................................................................55


D. Flowline Replacement .........................................................................57

1. Background ..............................................................................58

2. Projects Scope ..........................................................................58


E. Major Dams and Waterways Projects ..................................................59

1. Kaweah 1 - Flowline Rehabilitation ........................................59

a) Background ..................................................................59

b) Projects Scope ..............................................................59


2. Kern River 3 – Rebuild Tunnel ................................................60




-vi-

a) Background ..................................................................60

b) Projects Scope ..............................................................60


3. Borel - Rebuild Canal and Tunnels ..........................................60

a) Background ..................................................................60

b) Projects Scope ..............................................................61


4. Bishop 6 – Replace Flowline/Install AVM ..............................61

a) Background ..................................................................61

b) Projects Scope ..............................................................62


5. Mammoth Pool Reservoir HB Valve Replacement .................62

a) Background ..................................................................62

b) Projects Scope ..............................................................62


6. Northern Hydro Dams Structure and Seismic Retrofit Projects .......................................................................63

a) Background ..................................................................63

b) Projects Scope ..............................................................63


F. Dams and Waterways – Miscellaneous ...............................................63

1. Background ..............................................................................64

2. Projects Scope ..........................................................................64




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VI. STRUCTURES AND GROUNDS ..................................................................66

A. Building Improvement Projects ...........................................................66

1. Background ..............................................................................67

2. Project Scope ...........................................................................67


B. Road Improvement and Repaving .......................................................67

1. Background ..............................................................................68

2. Projects Scope ..........................................................................68


C. Major Structures and Grounds Projects ...............................................69

1. Bishop 4 – Water System/Install Domestic Well ....................69

a) Background ..................................................................69

b) Projects Scope ..............................................................69


2. Rush Creek Rebuild Tram Track & Replace Tram Car ............................................................................................70

a) Background ..................................................................70

b) Projects Scope ..............................................................70


3. Big Creek 1 Camp Cottage Renovations .................................70

a) Background ..................................................................70

b) Projects Scope ..............................................................71




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4. Big Creek 1 Construct Administration and Dispatch Office .......................................................................................71

a) Background ..................................................................71

b) Projects Scope ..............................................................71


D. Structures and Grounds – Miscellaneous Projects ...............................72

1. Background ..............................................................................72

2. Projects Scope ..........................................................................73


VII. FURNITURE, TOOLS AND EQUIPMENT ..................................................75

A. Furniture and Office Equipment ..........................................................75

B. Portable Tools and Equipment .............................................................75

C. Laboratory, Testing and Technical Equipment ....................................75

D. Miscellaneous Work Equipment and Spare Parts ................................76

E. Power Production Division (PDD) Home Office ................................76

VIII. DECOMMISSIONING - SAN GORGONIO ..................................................77

A. San Gorgonio Hydro Project ................................................................77

1. Background ..............................................................................77

2. Projects Scope ..........................................................................78


Appendix A Witness Qualifications

Appendix B SCE Hydro Capital Projects For 2013 – 2017 (Nominal Values are in $1000’s)


List Of Figures

Figure Page

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Figure I-1 Hydro Recorded, Authorized, and Forecast Capital Expenditures (Nominal $) ........................2

Figure I-2 SCE Hydro Capital Project Categories for 2013-2017 (Nominal $millions) .............................3


List Of Tables

Table Page

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Table I-1 SCE Hydro Capital Categories.....................................................................................................1

Table II-2 SCE Hydro FERC Licenses ........................................................................................................8

Table II-3 SCE Hydro FERC Relicensing Projects (Nominal $) ..............................................................14

Table III-4 Electrical Equipment Programs & Projects (Nominal $) .......................................................22

Table III-5 Infrastructure Projects (Nominal $) .........................................................................................23

Table III-6 Region Automation Projects (Nominal $) ...............................................................................27

Table III-7 Transformer Replacements (Nominal $) .................................................................................29

Table III-8 Branch Circuit, Control and Relay Panels (Nominal $) ..........................................................31

Table III-9 Circuit Protection Equipment (Nominal $) .............................................................................33

Table III-10 Major Electrical Projects (Nominal $) ..................................................................................34

Table III-11 Electrical Equipment – Miscellaneous Projects (Nominal $) ................................................37

Table IV-12 Prime Mover Major Programs & Projects (Nominal $) ........................................................39

Table IV-13 Turbine Wicket Gates, Runners, and Repowers (Nominal $) ...............................................40

Table IV-14 Generator Coils and Rewinds (Nominal $) ...........................................................................41

Table IV-15 Generator Excitation Projects (Nominal $) ...........................................................................43

Table IV-16 Turbine Valves and High Pressure Piping Systems (Nominal $) .........................................45

Table IV-17 Prime Mover Replacements (Nominal $) ..............................................................................47

Table IV-18 Prime Mover Miscellaneous (Nominal $) ............................................................................48

Table V-19 Dams and Waterways Major Programs & Projects (Nominal $) ..........................................50

Table V-20 Gates and Valves (Nominal $) ...............................................................................................51

Table V-21 Structures Improvement (Nominal $) ....................................................................................53

Table V-22 Dam Surface Protection (Nominal $) .....................................................................................55

Table V-23 Flowline Replacement (Nominal $) .......................................................................................58

Table V-24 Major Dams and Waterways (Nominal $) ..............................................................................59

Table V-25 Dams and Waterways Miscellaneous Projects (Nominal $) ..................................................64

Table VI-26 Structures and Grounds Major Programs & Projects (Nominal $) .......................................66

Table VI-27 Hydro Building Improvement Projects (Nominal $) .............................................................66

Table VI-28 Hydro Road Improvement and Paving (Nominal $) .............................................................68


List Of Tables (Continued)

Table Page

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Table VI-29 Major Structures and Grounds (Nominal $) ..........................................................................69

Table VI-30 Structures and Grounds – Miscellaneous (Nominal $) .........................................................72

Table VII-31 Furniture, Tools and Equipment (Nominal $) ......................................................................75

Table VIII-32 Decommissioning (Nominal $) ..........................................................................................77

1

I. 1

HYDRO GENERATION – CAPITAL EXPENDITURES PLAN DEVELOPMENT 2

SCE’s planned capital expenditures for its Hydroelectric (Hydro) generating facilities are 3

necessary to provide reliable service at low cost while complying with applicable laws and regulations, 4

and maintaining safe operations for employees and the public. This volume describes the Hydro capital 5

forecast for years 2013-2017. It describes the categories of expenditures, the driving forces behind 6

increasing capital costs, the need for these expenditures, and major capital projects. 7

A. Categories of SCE Hydro Capital 8

SCE determines the category for each SCE Hydro capital project by the type of capital asset 9

involved. Table I-1 below shows these categories. 10

Table I-1 SCE Hydro Capital Categories

Category Description of Major ItemsFederal Energy Commission (FERC) Relicensing FERC Relicensing, including mitigation costsDecommissioning Removal of significant assets from serviceElectrical Equipment Control systems, switchgear, transformersPrime Movers Turbines, generators & associated equipmentDams & Waterways Reservoirs, tunnels, flumes, penstocks, canalsStructures & Grounds Powerhouses, buildings, roads, bridges, wastewaterFurniture, Tools & Equipment Furniture, tools, spare parts, test equipment

B. 2013-2017 Hydro Capital Expenditure Estimate 11

SCE Hydro Division capital investments support is needed for infrastructure and equipment 12

replacement and our ongoing efforts to renew the Federal Energy Regulatory Commission (FERC) 13

licenses for many of our facilities. Infrastructure work generally includes projects such as dam 14

improvements that are needed to address areas of concern, flowline refurbishment, substation 15

refurbishment, powerline replacements, building refurbishment, and road improvements. Equipment 16

replacement work generally include projects such as transformers, automation, switchgear, hydro turbine 17

repowers, generator rewinds, and small generator replacements. 18

The total Hydro capital expenditure forecast is $438.293 million for 2013-2017 in nominal dollar 19

and is shown by year in Figure I-1 below. 2015 and 2016 expenditures show an increase as compared 20

historical spending levels. This increase is due to large projects, some of which are required by FERC 21

relicensing and are include within the Prime Movers, Dam Surface Protection, and Substation categories 22

2

that will occur during this period. Prior to 2015 and after 2016 expenditures will remain at levels that 1

are consistent with historical levels. 2

Appendix B contains a summary listing of the SCE Hydro five-year capital estimate for 2013-3

2017. The listing reflects the capital programs and projects discussed in the following testimony and are 4

divided into the appropriate sections. 5

Figure I-1 Hydro Recorded, Authorized, and Forecast Capital Expenditures

(Nominal $)

C. Recorded Capital Expenditures Compared To Previous GRC Authorized 6

In the approved 2012 GRC (D.12-11-051), SCE was authorized by the Commission to spend 7

$78.1 million in 2009, and $83.5 million in 2012, on capital projects. SCE recorded higher expenditures 8

than authorized in 2012, mainly due to additional funding that was required for both Prime Movers and 9

Structures and Grounds projects. 10

3

D. Hydro Capital Project Categories 1

Chapters II through VIII describe each category of capital expenditures identified below in 2

Figure I-2. 3

Figure I-2 SCE Hydro Capital Project Categories for 2013-2017

(Nominal $millions)

FERC Relicensing, $50.6

Structures & Grounds, $41.9

Dams & Waterways, $142.0

Prime Movers, $69.0

Electrical Equipment, $126.3

Decommissioning, $7.1 Furniture, Tools & Equipment, $1.4

Expenditures for Dams & Waterway projects account for almost one-third of the capital forecast, 4

or $142.0 million in 2013-2017. Major projects in Dams & Waterways include: 5

Applying geomembrane liners to dams to eliminate leakage. 6

Structural or seismic stability improvements to dams. 7

Dam spillway or instream water release improvements. 8

Tunnel flowline rehabilitation to restore flow and reliability. 9

Aging flowline replacement. 10

Flowline replacement due to wildfire damage. 11

The second largest category of capital expenditure is Electrical Equipment with $126.3 million in 12

2013-2017. Major Electrical Equipment projects include: 13

Hydro managed substation infrastructure replacements. 14

4

Automation upgrades to control systems. 1

Powerhouse transformer replacements. 2

Powerline replacements for power and control circuits to reservoirs. 3

The next largest category of capital expenditure is Prime Movers with $69.0 million in 2013-4

2017. Major Prime Mover projects include: 5

Turbine refurbishment projects to replace waterwheels or runners with associated equipment. 6

Generator rewinds for stators or rotors. 7

Replacement of aged small hydro generators used at instream releases. 8

The next largest category of capital expenditure (excluding FERC relicensing) is Structures & 9

Grounds with $41.9 million in 2013-2017. Structures & Grounds projects include: 10

Building improvements for powerhouses and field structures. 11

Building improvements for shops and offices. 12

Employee housing refurbishment and replacement. 13

Road improvements and paving. 14

Hydro relicensing continues as a significant category of capital expenditure and will require 15

$50.6 million in 2013-2017. Significant expenditures for relicensing will continue through 2017 before 16

decreasing significantly. 17

SCE must sustain these capital expenditure levels through 2017 for FERC relicensing, dam and 18

waterway work, and equipment replacement. Both testimony and workpapers include project 19

descriptions and justifications for capital projects forecasted for 2013-2017. 20

E. Creation of the GRC Capital Forecast 21

This GRC capital expenditure forecast consists of over 240 individual capital projects that have 22

been combined into a five-year 2013-2017 forecast. The projects included have been selected by criteria 23

mentioned below and approved by SCE senior management for inclusion in this GRC. The capital 24

projects identified for 2013-2017 vary in the amount, definition, and knowledge available at the time 25

that this forecast is done. Projects planned for 2013 and 2014 will have more planning and engineering 26

done at this time than projects further out on the horizon in 2015 to 2017. As additional work is done on 27

those future projects, priorities and costs are subject to change. Nonetheless, we strive to assemble as 28

accurate a forecast as possible for review at this time. 29

5

1. Planning for Capital Expenditures 1

Staffs from both Hydro regions, Northern and Eastern, meet on a monthly basis to 2

determine the need for all capital projects and confirm or reassign capital project priorities based upon 3

the needs of their region. In these meetings we investigate each project based upon the following 4

aspects: 5

Strategic, regulatory, environmental, or health and safety importance; 6

Economic value based on generation and/or reliability; and 7

Readiness of the project to proceed. 8

Each Hydro region maintains a list of all capital projects sorted by decreasing priority. 9

The categories of projects from highest to lowest priority are: (1) sustaining or improving safety where 10

needed; (2) regulatory and environmental compliance; and (3) preserving electric reliability and 11

minimizing the potential for lost generation. 12

The capital budget for each year reflects the total expenditures for capital projects 13

planned for that year. Inevitably, capital projects can change in scope, cost, and timing. The Hydro 14

regions control these changes, while managing all necessary projects within the total capital budget. 15

After Hydro management approval, the corporate Capital Review Team reviews large projects 16

exceeding $10 million. 17

2. Capital Estimating Process 18

Capital project estimates are prepared by knowledgeable experts in the field and staff 19

offices. Northern and Eastern Hydro both maintain a staff of mechanical, electrical, and civil engineers. 20

In addition to the Hydro staff, the Engineering and Technical Services (E&TS) staff located in San 21

Dimas also support this effort. E&TS employs engineers in the multiple disciplines of electrical, 22

mechanical, civil, structural, and geotechnical engineering, as well as experts in control systems, 23

transformers, switchyards, performance engineering, technical inspections, cost engineering, and 24

construction management. 25

Capital projects are typically proposed with conceptual estimates to determine feasibility 26

and timing of the project.1 Often, prior similar projects provide a solid basis for cost estimates. As the 27

project approaches initiation, a preliminary estimate is performed in order to better quantify the project 28

1 A conceptual estimate according to Association for Advancement of Cost Engineering International (AACEI) is an

estimate made without the benefit of detailed engineering data. It is in the same category as their Class 4 estimate which is generally prepared based on limited information and subsequently has fairly wide accuracy ranges. They are typically used for project screening, determination of feasibility, concept evaluation, and preliminary budget approval.

6

cost and determine lead times for critical equipment. Typically, final engineering is performed prior to 1

project initiation. Certain projects may require that final engineering is done concurrently with the 2

work. Project costs are often calculated by our expert staff at the field or home office locations. When 3

appropriate, vendor quotes are utilized to substantiate costs. For projects that are already in progress, 4

our estimates are based on expenditures recorded to date and the amount of remaining work to be 5

completed. This often incorporates purchase orders and other contracted dollar amounts. 6

7

II. 1

FERC LICENSING PROJECTS 2

Thirty of SCE Hydro’s 35 powerhouses are subject to federal regulations requiring the Federal 3

Energy Regulatory Commission (FERC) licenses to operate. Twenty FERC licenses govern operation 4

of these 30 powerhouses. These 30 powerhouses account for 1,171 MW of our total Hydro nameplate 5

capacity of 1,176 MW. FERC includes operating requirements that SCE must meet as conditions of 6

these licenses. These requirements typically include maintaining minimum stream flows and reservoir 7

levels, conducting periodic assessments of our operations impact on environmental and cultural 8

resources, constructing and maintaining nearby recreational facilities, and submitting periodic reports. 9

FERC grants each license for a defined period. SCE must renew the license upon expiration to 10

continue project operation. SCE’s original licenses were for a 50-year term, and most renewed licenses 11

now have a 30-year to 40-year term. FERC relicensing is time-consuming and costly. SCE must 12

prepare voluminous reports and perform numerous studies. Once a new license is granted, we typically 13

incur mitigation costs and restrictions on our operations that are greater than those required by the 14

previous license. These mitigation costs may include a reduction in our electrical generation output 15

because of requirements to divert less water away from the streambed for power generation. They may 16

also include increased studies of the environmental impact of our operations and additional recreational 17

studies and improvements. 18

Despite the significant cost of FERC relicensing, these facilities provide substantial benefits to 19

customers over the license period. To provide intergenerational equity, SCE capitalizes FERC 20

relicensing costs rather than expensing them as incurred. This practice is consistent with Generally 21

Accepted Accounting Principles (GAAP) and is accepted utility practice. 22

SCE is in the relicensing process for six of the 20 FERC licenses it holds. These six licenses are 23

for Big Creek projects that account for approximately 915 MW of nameplate capacity, or approximately 24

77.8 percent of SCE's total hydro capacity of 1,176 MW. SCE has also received 11 additional FERC 25

licenses within the last 14 years. Five of these 11 licenses require continued capital expenditures for 26

studies or mitigation costs as a license condition. Combined, the six licenses that are in process of 27

relicensing, and the five previously awarded licenses, will require capital expenditures of $50.590 28

million during 2013-2017, or 12 percent of the total five-year forecast expenditures for all Hydro capital 29

projects. The sites governed by these 11 licenses account for approximately 1,059 MW of our total 30

Hydro capacity of 1,176 MW, or 90 percent. 31

8

Table II-2 summarizes the relicensing status for each of our generating plants. A discussion of 1

the FERC relicensing process and SCE's relicensing cost estimate follows Table II-2. This testimony 2

then addresses each FERC relicensing action requiring capital expenditures during 2013-2017. 3

Table II-2 SCE Hydro FERC Licenses

Relicense Status

FERC Project

License Expiration Notes

Nameplate Capacity MW

Northern Hydro RegionBig Creek Nos. 1 & 2 Ongoing 2175 2/28/2009 (c)(d)(e) 154.85 Big Creek Nos. 2A, 8 & Ongoing 67 2/28/2009 (c)(d)(e) 384.80

John S. EastwoodBig Creek No. 3 Ongoing 120 2/28/2009 (c)(d)(e) 174.45 Big Creek No. 4 Recent 2017 11/30/2039 100.00 Portal Ongoing 2174 3/31/2005 (c)(e) 10.80 Mammoth Pool Ongoing 2085 11/30/2007 (c)(e)(d) 190.00 Vermilion Valley Ongoing 2086 8/31/2003 (b)(c)(e) -

1,014.90 Eastern Hydro RegionKern River No. 1 Recent 1930 5/31/2028 26.28 Kern River No. 3 Complete 2290 11/30/2026 40.18 Borel Recent 382 5/17/2046 12.00 Lytle Creek Complete 1932 5/31/2033 0.50 Santa Ana Nos. 1 & 3 Complete 1933 6/30/2033 6.30 Mill Creek No. 3 Recent 1934 6/30/2033 3.00 San Gorgonio Nos. 1 & 2 None 344 4/26/2003 (a) - Bishop Creek 2, 3, 4, 5 & 6 Complete 1394 6/30/2024 29.25

Lee Vining Creek (Poole) Complete 1388 1/31/2027 11.25 Rush Creek Complete 1389 1/31/2027 13.01 Mill Creek (Lundy) Recent 1390 2/28/2029 3.00 Kaweah Nos. 1, 2 & 3 Complete 298 12/31/2021 8.85 Lower Tule River Recent 372 7/31/2033 2.52

156.13 1,171.03

5.15 1,176.19

a) Planned for decommissioning and will not be relicensed.b) Storage only.c) Application for new license filed with the FERC.d) Will be relicensed under the Alternative Licensing Process

Notes:

Sub-Total Northern

e) Operating under an annually renewable license pending issuance of new term license.

Sub-Total Eastern

Capacity of Hydro plants without FERC licensesTotal FERC Licensed Plants

Total Hydro capacity

9

A. FERC Relicensing Process 1

FERC divides the licensing process into two phases: (1) a pre-application consultation phase; 2

and (2) a post-application analysis phase. During the pre-application consultation phase, the licensee 3

files a Notice of Intent (NOI) to seek an original, new, or subsequent license and enters into consultation 4

with resource agencies, stakeholders, and the public regarding the project. The post-application analysis 5

phase begins when the licensee files a formal application to obtain a new license. The application must 6

be filed no later than two years before the existing license expires. The application is a comprehensive, 7

detailed document specifying the project’s proposed operations, its anticipated impact on resources and 8

other land uses, and proposed actions to mitigate adverse effects. FERC reviews the application to 9

ensure that it meets all requirements and then asks relevant federal and state land and resource agencies 10

to formally comment. 11

Once FERC has determined that the application meets all of the filing requirements, the studies 12

have been completed, any deficiencies have been resolved, and no additional information is required, 13

FERC will issue the notice of acceptance and ready for environmental analysis (REA). The REA notice 14

triggers a deadline for comments, recommendations, and mandatory conditions or prescriptions. When 15

these filings are complete, FERC has all the information needed to prepare the National Environmental 16

Protection Act (NEPA) document. An Environmental Assessment (EA) or Environmental Impact 17

Statement (EIS) will typically be the NEPA document prepared for a license application. The licensing 18

process concludes with the issuance of a licensing order. FERC has completed the relicensing process 19

steps for all six Big Creek projects, with the exception of the issuance of a new license order. 20

The Federal Power Act (FPA) provides for subsequent administrative and judicial reviews of a 21

FERC license decision. If a license expires while a project is undergoing relicensing, FERC issues an 22

annual license, allowing a project to continue to operate under the conditions found in the original 23

license until the relicensing process is complete. All six Big Creek projects that are still undergoing the 24

relicensing process are currently operating under annual license renewals. Table II-2 above identifies 25

SCE’s FERC project license numbers and the associated expiration date for each license. 26

FERC regulations governing the relicensing of an existing hydroelectric project allow the 27

licensee to use the Alternative Licensing Process (ALP), Traditional Licensing Process (TLP), or the 28

Integrated Licensing Process (ILP)2 to prepare, file, and process a new license application. In the Big 29

2 In July 2003, FERC added a third relicensing process called the Integrated Licensing Process; however, this was not

available in time for any of the SCE relicensing projects discussed herein.

10

Creek System, SCE is utilizing both the TLP and the ALP to relicense six of the seven FERC Licensed 1

Projects. The two projects being relicensed using the TLP are the Vermilion Valley Hydroelectric 2

Project (FERC No. 2086) and the Portal Hydroelectric Project (FERC No. 2174). The four FERC 3

projects being relicensed using the ALP are the Mammoth Pool Project (FERC No. 2085); Big Creek 4

Nos. 1 and 2 Project (FERC No. 2175); Big Creek Nos. 2A, 8 and Eastwood Project (FERC No. 67); 5

and Big Creek No. 3 Project (FERC No. 120). 6

1. Alternative Licensing Process (ALP) 7

The ALP is a multi-year collaborative process that allows the consultation and 8

environmental review phases of relicensing to be combined into a single process. Under this process the 9

applicant conducts a preliminary NEPA analysis during the pre-application phase rather than having 10

FERC begin the NEPA analysis during the post-application phase. Also, the applicant prepares a 11

preliminary draft environmental assessment (PDEA) that is filed with the application for new license. 12

The ALP seeks to improve communication and collaboration among the applicant and stakeholders 13

during the process and often results in a “settlement agreement” at the end of the pre-application phase. 14

This settlement agreement, signed by all the participants in the process, includes the conditions to 15

protect and enhance resources and, if reached, is filed with the application for new license. 16

2. Traditional Licensing Process (TLP) 17

The TLP consists of a three-stage consultation process for the preparation and filing of a 18

new license application for an existing hydroelectric project. Under this process, the applicant prepares 19

and submits a license application to the FERC presenting information about the project, the resources in 20

the project area, and the licensee’s protection, mitigation and enhancement (PM&E) proposals along 21

with those measures proposed by other parties, but not adopted by the licensee. The FERC conducts an 22

independent environmental review of the project, and during this time resource agencies, Native 23

American tribes, the public, and the applicant can provide comments. The FERC will issue a new 24

license order with terms and conditions based on the PM&E measures proposed in the license 25

application and on stakeholder comments received during the review period. The TLP was previously 26

the only process available to a licensee. 27

B. Big Creek Relicensing Projects 28

1. Background 29

Six of Big Creek’s seven FERC project licenses are in the midst of relicensing activity as 30

mentioned above. The Big Creek No. 4 Project (FERC No. 2017) has already completed its relicensing 31

11

process and received a new FERC license in 2003. Four Big Creek projects are being relicensed in a 1

single ALP and two projects are being relicensed individually using the TLP. SCE elected to use the 2

multi-year collaborative ALP for relicensing four of its Big Creek projects to address complex resource 3

balancing issues within a single process. The Vermilion Valley and Portal projects were not 4

incorporated into the ALP because earlier FERC License expiration dates required that their licensing 5

process to begin sooner than the initiation of the ALP. 6

a) Big Creek ALP Projects Relicensing 7

The Big Creek ALP began in May 2000 after receiving FERC approval to use the 8

process. On October 30, 2002 SCE filed its NOIs to file an application for the Mammoth Pool Project 9

and on February 27, 2004, SCE filed its NOI to file applications for the three remaining Big Creek ALP 10

projects. FERC is processing all four projects simultaneously in a single ALP. By combining these four 11

relicensing projects into a single ALP, SCE expects a better outcome compared to pursuing each 12

relicensing individually. This process gives SCE greater input into the mitigation activities and costs 13

resulting from relicensing actions. During the implementation of the ALP SCE: (1) developed, 14

implemented and evaluated the results of technical resources studies designed to access the effects of 15

project operations on environmental and cultural resources; (2) prepared the license applications and a 16

preliminary draft environmental assessment (PDEA); and (3) negotiated a comprehensive settlement 17

agreement with stakeholders that included the proposed terms and conditions for the projects over the 18

terms of the new license orders which was filed with the applications for new license. The Settlement 19

Agreement was signed by 21 signatories including the California Department of Fish and Game 20

(CDFG), the U.S. Department of Agriculture-Forest Service (USDA-FS), the Fish and Wildlife Service 21

(FWS), and the Friant Water Authority and included the support of the California State Water Resources 22

Control Board (State Water Board). SCE anticipates that FERC will model the new license 23

requirements on the Settlement Agreement without significant additional requirements. 24

Since the filing of the license application for the ALP projects, FERC has 25

completed their NEPA process with the issuance of a Final Environmental Impact Statement (FEIS) on 26

March 13, 2009. FERC has completed their relicensing process and is waiting for the State Water Board 27

to issue a Water Quality Certification (WQC) for the projects in accordance with the requirements of the 28

Clean Water Act before it can issue a new license order. The existing licenses for the Big Creek ALP 29

Projects have expired. The licenses for the ALP projects have expired and FERC has issued Notice of 30

12

Authorization(s) for Continued Project Operation, which allows the projects to operate on annual 1

renewals until new license orders are issued. 2

b) Portal Hydroelectric Project Relicensing 3

SCE initiated relicensing of the Portal Hydroelectric Project on March 28, 2000 4

with the filing of its NOI to file an application for new license. SCE filed its application for new license 5

on March 26, 2003 and FERC prepared and issued a Final Environmental Assessment (FEA) on April 6

27, 2006. As described for the ALP Projects above, FERC has completed their relicensing process and 7

is waiting for the State Water Board to issue a WQC for the Project before it can issue a new license 8

order. The current license expired on March 31, 2005; however, FERC issued a Notice of Authorization 9

for Continued Project Operation on September 10, 2003, which automatically allows continued 10

operation of the Project until issuance of a new license. 11

c) Vermilion Valley Hydroelectric Project Relicensing 12

SCE initiated relicensing of the Vermilion Valley Hydroelectric Project on 13

August 24, 1998 with the filing of its NOI to file an application for new license. SCE filed its 14

application for new license on August 29, 2001 and FERC prepared and issued an Environmental 15

Assessment (EA) for the Project on May 4, 2004. As described for the Big Creek ALP Projects above, 16

FERC has completed their relicensing process and is waiting for the State Water Board to issue a WQC 17

for the project before it can issue a new license order. The current license expired on August 31, 2003; 18

however, FERC issued a Notice of Authorization for Continued Project Operation on September 10, 19

2003, which automatically allows continued operation of the Project until issuance of a new license. 20

d) Licensed Big Creek 4 Project 21

On December 4, 2003, FERC issued a new license for the Big Creek No. 4 22

Project. Under the new license order SCE was required to prepare resource management plans that 23

include PM&E measures designed to avoid and protect sensitive environmental and cultural resources. 24

SCE is complying with all the conditions of the new license and the resource management plans that 25

were approved by the resource agencies. 26

2. Delay of License Issuance 27

The issuance of new license orders for the six Big Creek projects has been delayed 28

because the FERC is waiting for a WQC from the State Water Board. FERC has completed their 29

process to comply with the NEPA requirements for the issuance of all six Project licenses. However, 30

13

FERC must also comply with the California Water Quality Act, which requires the issuance of a WQC. 1

The State Water Board is the lead agency responsible for issuance of the WQC. 2

The State Water Board intends to issue a single WQC for all six projects. However, 3

before the State Water Board can issue a WQC, it must evaluate the projects in accordance with the 4

requirements of the California Environmental Quality Act (CEQA). To fulfill its obligation under 5

CEQA, the State Water Board is using the March 2011 FEIS for the Big Creek ALP Projects, along with 6

the 2004 and 2006 FEAs for both the Vermilion Valley and Portal projects, to complete much of the 7

environmental analysis required by CEQA. However, the State Water Board must also prepare a 8

supplemental document to FERC’s EIS that will address additional environmental analysis that is 9

required under CEQA. 10

At the request of the State Water Board, SCE has prepared and provided a draft 11

supplemental document that addresses the additional CEQA environmental analysis. SCE provided the 12

supplemental document to the State Water Board on November 9, 2011. The State Water Board is 13

preparing a draft WQC that will include mandatory conditions, which are anticipated to be consistent 14

with the terms and conditions included with the ALP Settlement Agreement. The State Water Board 15

will circulate the draft WQC and the CEQA Supplemental Document for public review and comment 16

prior to issuing a final WQC for all sic Big Creek projects. 17

C. Relicensing Cost Forecast 18

SCE’s cost forecast for the implementation of the new license orders for the six Big Creek 19

projects is based on experience from the implementation of the new license order issued for the Big 20

Creek No. 4 Project in 2003. Many of the activities completed to support the implementation of the Big 21

Creek No. 4 License are carried forward into the Big Creek ALP, Vermilion Valley, and Portal projects. 22

The new license orders for the six Big Creek projects when issued will require the development of 23

resource agency approved management and protection plans, implementation of adaptive management 24

environmental resource studies over the term of the license, and preparation of license compliance tools 25

as well as data management databases. These same activities were completed for the Big Creek No. 4 26

Project. Therefore, based on this experience, SCE could subsequently quantify anticipated costs based 27

on similar work completed for the Big Creek No. 4 Project. The costs for 2013-2017 are shown below 28

on Table II-3 for individual Hydro projects. 29

When FERC relicensing begins for a specific Hydro facility, SCE opens a capital work order. 30

SCE records expenditures in this work order until the expiration date of the existing license, which also 31

14

becomes the in-service date for the capital expenditures incurred up to that point in time. Expenditures 1

recorded up to this date are then “in-service” and eligible for inclusion in rate base. Subsequent capital 2

expenditures related to gaining the new license generally record to this existing work order, to be placed 3

in service as the additional relicensing-related work proceeds. Capital projects relating to large FERC 4

license-related mitigation projects receive separate work orders. 5

SCE forecasts the capital necessary for FERC relicensing projects for five years ahead and 6

updates this forecast on an annual basis. The Big Creek ALP FERC relicensing effort includes the first 7

seven Hydro projects in Table II-3 below: Big Creek 1, 2, 3, 8, 2A, Eastwood, and Mammoth Pool. 8

Our total relicensing expenditure forecast is $50.590 million for 2013-2017. 9

Table II-3 SCE Hydro FERC Relicensing Projects

(Nominal $)

REF WBS Element FERC Relicensing 2013 2014 2015 2016 2017 TOTAL1 CG0-00-PP-HN-000046 Big Creek 1 Relicensing 668 3,169 1,064 740 1,905 7,545 2 CG0-00-PP-HN-000047 Big Creek 2 Relicensing 668 3,169 1,064 740 1,905 7,545 3 CG0-00-PP-HN-000049 Big Creek 8 Relicensing 2,295 1,033 1,587 625 1,042 6,583 4 CG0-00-PP-HN-000050 Big Creek 3 Relicensing 195 298 294 500 825 2,111 5 CG0-00-PP-HN-000051 Big Creek 2A Relicensing 2,295 1,033 1,587 625 1,042 6,583 6 CG0-00-PP-HN-000052 Mammoth Pool Relicensing 200 1,152 132 25 390 1,899 7 CG0-00-PP-HN-000053 Eastwood Relicensing 2,295 1,033 1,587 625 1,042 6,583 8 CG0-00-PP-HN-000054 Vermillion Relicensing 423 1,397 824 253 2,630 5,527 9 CG0-00-PP-HN-000055 Big Creek 4 Relicensing 933 842 215 - - 1,990 10 CG0-00-PP-HN-000056 Portal Relicensing 223 2,497 566 205 735 4,226

(Nominal Values are in $1000's) Total 10,194 15,622 8,920 4,338 11,517 50,590

FERC RELICENSING

1. Big Creek Alternative Licensing Procedure 10

The total 2013-2017 capital expenditure forecast for Big Creek ALP is $38.847 million 11

(Ref.3 1-7). The Big Creek ALP activities can be divided into two main categories: (1) preparing for 12

license issuance; and (2) permitting and planning activities associated with the implementation of new 13

license terms. 14

a) Implementation of New License Order Terms and Conditions 15

As stated above, the issuance of the new ALP license is expected in late 2013 or 16

early 2014. Prior to license issuance, a 401 WQC must be issued by the State Water Board. In 17

preparation for the new license, several tools are also being developed to assist in the tracking and 18

compliance of the new license order(s). These tools include License Implementation Tracking Tools 19

3 “Ref” for projects listed in this testimony refers to corresponding references on related Tables.

15

and an Environmental Compliance Database (ECD). The License Implementation Tracking Tools 1

include the development of management tools, which identify and cross reference consultation, 2

implementation, monitoring, and reporting requirements. The tools consist of resource management 3

plan summaries, reporting and consultation requirements, decision records, flow charts to track and 4

monitor activities, and a project timeline and calendar. The ECD is a GIS based tool that identifies 5

biological and cultural resources and associated PM&E measures associated with the operation and 6

maintenance of the Big Creek ALP Projects. 7

The major relicensing costs to SCE associated with future project operations are 8

related to implementing the license order terms and conditions including the required resource 9

management plans and license articles as set forth in the Settlement Agreement. There are five main 10

resource areas (Aquatic Resources, Recreational Resources, Terrestrial Resources, Land Management, 11

and Cultural Resources) that require additional studies, enhancements, or mitigation measures to comply 12

with the terms of the Settlement Agreement. Each resource area is discussed below. 13

b) Aquatic Resources 14

Enhancements and mitigation measures that address aquatic resources were 15

designed to mitigate project impacts identified in studies and enhance habitat conditions for aquatic life. 16

The following describes the types of activities SCE will be required to complete including some of the 17

associated monitoring or mitigation activities. 18

Channel riparian maintenance (CRM) flows will be released along two selected 19

reaches to provide enhanced habitat that will sustain aquatic and riparian ecosystems. Prior to the high 20

flow releases on Mono Creek, baseline measurements of the current sediment and riparian conditions 21

will be conducted within the first year following license issuance. Along the South Fork San Joaquin 22

River below Florence Reservoir, a detailed topographic survey of the Jackass Meadow Complex will be 23

performed prior to the CRM flow releases. Subsequent surveys will be conducted to determine the 24

extent of inundation from the CRM flows. Riparian conditions along the stream corridor will also be 25

conducted within the first year following license issuance. 26

Four back country hydropower diversions and two domestic water diversions are 27

to be decommissioned and the natural flows returned to the channel. All six diversions are proposed for 28

removal within five years following license issuance. To complete the decommissioning at each 29

location, applicable permits will be obtained and supporting documentation will be prepared in 30

consultation with resource agencies. 31

16

Stream and reservoir temperatures will be monitored during the first three to five 1

years that instream flows are released under the new project licenses to demonstrate that temperature 2

targets are consistently met. Installation and ongoing maintenance or calibration of the stream 3

temperature recorders will occur throughout the monitoring period. 4

An Interim Water Temperature Control Program will be prepared in consultation 5

with resource agencies. The Interim Program will contain measures that may be feasibly implemented 6

by SCE to maintain water temperature targets in project stream reaches. Additional water temperature 7

studies and modeling will be included as a component of the Interim Program and the results will be 8

integrated into the Long-Term Water Temperature Control Program. 9

Fish populations will be monitored in selected stream reaches in order to assess 10

the effects of the newly agreed upon stream flow releases on fish community composition and 11

abundance. Night snorkeling surveys will also be conducted at several established sampling sites prior 12

to the implementation of the new minimum instream flows. 13

Sediment stored behind project dams and diversions will be reduced through the 14

implementation of sediment management prescriptions that include sediment pass through or physical 15

removal of sediment. Sediment management activities are required to maintain proper operation of the 16

projects and protect facility reliability (low-level outlets and intake structures). Initial agency 17

consultation and draft permit applications for the CDFG 1600 Streambed Alteration Agreement and an 18

Army Corp of Engineers (ACOE) Section 404 permit will be obtained prior to implementation of the 19

sediment management prescriptions. 20

Baseline studies to establish fine sediment in pools will also be conducted prior to 21

implementing sediment management prescriptions. During the implementation SCE will monitor water 22

quality and fine sediment conditions associated with the sediment pass through prescription. 23

Instream flow release improvements include installation, modification, and 24

maintenance of flow monitoring equipment and/or release structures at 21 stream gaging stations. At 25

locations where infrastructure changes are proposed to comply with the new instream flow release 26

requirements, preliminary engineering designs, permitting, and construction will occur. 27

A gravel augmentation program is proposed below Mammoth Pool Dam to 28

improve trout recruitment by providing additional spawning gravel to the reach. SCE will initiate 29

agency consultation on the feasibility of adding gravel to the channel and will prepare necessary permits 30

and supporting documents to implement the plan. 31

17

c) Recreational Resources 1

Under the new license orders, SCE will be required to maintain and enhance 2

recreational resources by operating and maintaining recreation facilities and through the rehabilitation, 3

replacement, and improvement of recreation facilities in the vicinity of the ALP Projects. 4

During the five years from 2013 to 2017, SCE will conduct major rehabilitation at 5

five campgrounds and three day-use areas around two major SCE reservoirs. Major rehabilitation 6

consists of conceptual planning, engineering design, permitting, and construction of the facility. In 7

accordance with the terms of the Settlement Agreement, SCE initiated the recreation facility major 8

rehabilitation program upon the signing of the ALP Settlement Agreement. SCE completed the 9

rehabilitation of a 149-site campground in 2012 and will complete the rehabilitation of two 10

campgrounds and one day use area in 2013. Between 2014 and 2016, SCE will complete the 11

construction of two campgrounds, a day use area, a visitor’s center and a boat ramp, as well as initiate 12

the planning, design, and permitting for one campground, a boat ramp, and a day use area. 13

Upon license issuance, three new recreation facility capital improvements (day 14

use area, accessible boat landing facility and as accessible fishing platform) will be planned, designed 15

and constructed in conjunction with the major rehabilitation activities described above. Additionally, 16

several interpretative display exhibits (kiosks) will also be included with the major rehabilitation 17

activities. SCE will support fish stocking in project reservoirs and bypass stream reaches below project 18

diversions in order to enhance angling opportunities. Whitewater flow releases will be provided below 19

various diversions and dams in Wet and Above Normal Water Years to enhance recreational 20

opportunities. SCE will enhance recreation opportunities in the vicinity if the projects by providing 21

funding to the USDA-FS to: (1) Repair and maintain recreational facilities around the project area; (2) 22

Conduct minor rehabilitation of recreational facilities; and (3) Support Interpretive Programs. 23

SCE will also fulfill financial obligations as outlined in the Non-FERC Settlement 24

Agreement4 to other non-government groups. Examples include the Huntington Lake Association, 25

Huntington Lake Big Creek Historical Conservancy, and the Shaver Crossing Railroad Station Group. 26

d) Terrestrial Resources Measures 27

Under the new license order, SCE will implement avoidance and protection 28

measures for terrestrial resources potentially affected by project operations. Resource specific 29

management plans were developed to address these areas and include the Bald Eagle Management Plan, 30

4 An agreement to perform defined requirements entered into with non-governmental agencies.

18

Valley Elderberry Longhorn Beetle Plan, and Vegetation and Integrated Pest Management Plan. The 1

following activities will be conducted as required by the plans: (1) wintering and nesting surveys to 2

monitor the status of bald eagles in the vicinity of the Big Creek projects; (2) monitoring of the VELB 3

mitigation site; (3) monitoring of special status plant species and Native American plant populations; (4) 4

treatment and monitoring of noxious weed populations; and (5) conducting employee training on various 5

resource topics. 6

e) Land Management 7

Under the new license orders, SCE will implement resource management plans 8

for visual and transportation resources. The Visual Resource Plan will be implemented to addresses 9

visual effects of project facilities on the surrounding landscapes and view shed in the USDA-FS. 10

Several project facilities affecting visual resources will be repainted during their normal painting 11

schedule with natural colors that blend in with the surrounding environments and are approved by the 12

USDA-FS. 13

The Transportation System Management Plan describes measures that SCE will 14

implement to repair, minimize, or eliminate impacts associated with the maintenance and operation of 15

the projects. SCE will coordinate with the USDA-FS to conduct initial road condition surveys of SCE 16

maintained roads to identify and prioritize roads requiring rehabilitation. Any roads identified as 17

requiring immediate rehabilitation will be documented in the Annual Plan of Operations and scheduled 18

for repair the following year. 19

SCE will also establish a transportation signage fund in coordination with the 20

USDA-FS. This fund will allow the USDA-FS to purchase, repair, and maintain road and recreation use 21

signs throughout the Big Creek project area. 22

f) Cultural Resources 23

Under the new license order SCE will implement the Historic Properties 24

Management Plan (HPMP) prepared for the ALP projects. Activities associated with the 25

implementation of the HPMP include: 26

Establishing an advisory committee to periodically review and revise the 27

HPMP that will meet twice a year during the first five years following license 28

implementation. 29

Completing historic preservation activities called for in the HPMP within two 30

years following license issuance, including: (1) evaluation or determination 31

19

of National Register of Historic Places (NRHP) eligibility of some resources; 1

(2) a public education and interpretation program; (3) design, manufacturing, 2

and installation of Advisory and Educational/Interpretive Signage; (4) an SCE 3

Employee Education Program; (5) a plan to manage Unanticipated 4

Discoveries; (6) a NAGPRA Plan of Action for archaeological data recovery 5

excavations; (7) nomination of the Big Creek Hydroelectric System Historic 6

District to the National Register; and (8) a maintenance and repair plan for 7

historic buildings and structures associated with the Big Creek Hydroelectric 8

System Historic District. 9

Coordinating and assisting in the facilitation of the Native American Advisory 10

Group. 11

Fulfilling financial obligations as outlined in the Non-FERC Settlement 12

Agreement, including: (1) designation of lands for Native American Use; (2) 13

establishing a Native American Scholarship Fund; (3) contributing to the 14

Sierra Mono Museum Curation Funding; (4) improved pedestrian access and 15

protection of cultural resources at Mono Hot Springs; and (5) providing 16

training to SCE employees regarding environmental and cultural awareness. 17

2. Vermilion Valley Relicensing 18

The capital spending for Vermilion Valley Project forecast for 2013-2017 is $5.527 19

million (Ref. 8). SCE estimated these costs primarily on the basis of the USDA-FS final conditions 20

submitted to the FERC, FERC staff recommendations included in the Final Environmental Assessment 21

for the Project, and SCE’s experience from work conducted during the relicensing studies and 22

completed for the Big Creek No. 4 Project. 23

In preparation for the new license, SCE is developing the same license compliance tools 24

for the Vermilion Valley Project as discussed above for the Big Creek ALP Projects. These tools 25

include License Implementation Tracking Tools and the GIS based ECD. The new license will require 26

the development of several resource management plans as wells as implementing FERC required 27

studies, including: (1) implementing a Mono Creek Ramping Rate Study Plan to evaluate ecological 28

effects of rapid flow and stage fluctuations resulting from operational flow releases into the Mono Creek 29

and Warm Creek project bypass reaches; (2) refining and developing a Sediment Management Plan 30

including study site selection in and along the Warm Creek Diversion Channel, and identify and 31

20

evaluate alternatives to reduce sediment delivery from the Warm Creek Diversion Channel to Boggy 1

Meadow Creek; (3) conducting macroinvertebrate monitoring in Mono Creek below Vermilion Valley 2

Dam to assess the effect of water quality from the Vermilion Valley Dam leakage channel on stream 3

biota, as indicated by the macroinvertebrate community; (4) collecting water quality samples in Mono 4

Creek to evaluate iron concentrations in Vermilion Valley Leakage channels and Mono Creek; (5) 5

obtaining agreements with CDFG of future fish stocking of Lake Thomas A. Edison and Mono Creek; 6

(6) coordinating with the USDA-FS to conduct initial road condition surveys of SCE maintained roads; 7

(7) performing major rehabilitation of recreation facilities at the Vermilion Valley Project including 8

Vermilion Valley Campground, Boat Launch and Vista Overlook, and; (8) implementing the HPMP. 9

3. Big Creek No. 4 Relicensing 10

SCE forecasts $1.990 million in capital expenditures for Big Creek No. 4 for 2013-2017 11

(Ref. 9). SCE is complying with all the conditions of this new license, which include aquatic and 12

recreational studies associated with the Adaptive Management Plan (AMP) and Native Aquatic Species 13

Management Plan (NASMP) and recreation construction projects related to USDA-FS conditions. 14

SCE will implement aquatic studies outlined in the FERC approved AMP/NASMP, 15

which requires that SCE characterize the native aquatic community in the Horseshoe Bend reach in spill 16

and non- spill years to evaluate the effect of out of season flow releases on the native aquatic community 17

during spill and non-spill years. SCE will collaboratively consult with stakeholders in the Technical 18

Review Group (TRG) to coordinate the required studies and implementation schedule with the TRG. 19

SCE will prepare annual reports summarizing study results for TRG review and will provide annual 20

adaptive management proposals to the TRG for the implementation of adaptive management studies in 21

subsequent years. SCE will complete the AMP/NASMP required studies, which include but are not 22

limited to the following: (1) characterizing native transition-zone fish community in the Horseshoe 23

Bend Reach, the lower extent of Willow Creek; (2) conducting water temperature monitoring in the 24

Horseshoe Bend Reach and in Willow Creek; (3) conducting thermal and physical profile measurements 25

(water temperature, stratification, dissolved oxygen and specific conductance) at four sites in Redinger 26

Lake, and measure water temperature and Dissolved Oxygen profiles in pools in the San Joaquin River 27

downstream of Dam 7 to evaluate stratification; (4) conducting video monitoring of whitewater boating 28

use on the Horseshoe Bend Reach and perform visual verification of whitewater boating use to validate 29

the accuracy of boating counts collected using video; and (5) evaluating the effect of out of season flow 30

releases (flow magnitudes will be high enough to support recreational whitewater boating) on the native 31

21

aquatic community flow by monitoring the condition of the aquatic community before and after the 1

release flow. 2

SCE will construct a general recreation access trail beginning near County road 225 and 3

ending at the San Joaquin River near its confluence with Willow Creek. Trail design plans were 4

presented in the Final Design Package submitted to the USDA-FS and FERC. The trail project will be 5

constructed once the USDA-FS completes its NEPA analysis of the Project and after the appropriate 6

construction permits have been obtained. 7

4. Portal Relicensing 8

The capital forecast for Portal relicensing efforts is $4.226 million for 2013-2017 9

expenditures (Ref. 10). SCE estimated these costs primarily on the basis of the USDA-FS final 10

conditions submitted to the FERC, FERC staff recommendations included in the Final Environmental 11

Assessment for the Project, and SCE’s experience from similar work conducted during the relicensing 12

studies and completed for the Big Creek No. 4 Project. 13

In preparation for the new license, SCE is developing the same license compliance tools 14

for the Portal Project as discussed above for the ALP projects. These tools include License 15

Implementation Tracking Tools and the GIS based Environmental Compliance Database. The new 16

license will require the development of several resource management plans as well as implementing 17

FERC required studies, including: (1) developing a Sediment Management Plan to monitor fine 18

sediment accumulation in Camp 61 Creek below the diversion and to address project-related sediment 19

sources in Adit 2 Creek; (2) developing conceptual approaches to control erosion in Adit 2 Creek (i.e., 20

channel modifications or prescriptive measures); (3) conducting reconnaissance level surveys to monitor 21

the status and trends of the riparian resources along Camp 61 Creek below Portal Dam in response to the 22

riparian enhancement flow and minimum instream flow releases required under the new license release 23

and channel riparian maintenance flows where none were previously required; (4) implementing the Iron 24

Residue Removal Feasibility Study during engineering and re-design of the catchment basin below 25

Portal Dam and develop a Water Quality Sampling Plan to collect and analyze water samples to 26

determine the effectiveness of the iron residue removal activities; (5) obtaining agreements with 27

California Department of Fish and Game (CDFG) of fish stocking of Portal Forebay; (6) coordinating 28

with the USDA-FS to conduct initial road condition surveys of SCE maintained roads; (7) performing 29

major rehabilitation of recreation facilities at Portal Forebay including the campground and dispersed 30

use area, and; (8) implementing the Historic Preservation Management Plan (HPMP). 31

22

III. 1

ELECTRICAL EQUIPMENT 2

This section describes the electrical equipment at the Hydro plants that needs to be refurbished or 3

replaced. Control systems, circuit protection, and transformers wear out over time and require 4

replacement. Larger projects in this category typically involve complete replacement of excitation 5

equipment, high voltage plant circuit breakers, transformers, or automation work. Excitation equipment 6

provides the power to a generator’s field windings, which is necessary to produce output power. Plant 7

circuit breakers are large devices that protect and disconnect Hydro plants from the transmission 8

network. Step-up transformers convert the Hydro plant voltage to that of the transmission network or 9

grid. Automation equipment is used to remotely or efficiently control processes at powerhouses as well 10

as ancillary facilities. 11

The Electrical Equipment capital expenditure forecast for Hydro projects is $126.277 million for 12

2013-2017. The following Table III-4 shows the major programs and projects for the Electrical 13

Equipment category. 14

Table III-4 Electrical Equipment Programs & Projects

(Nominal $)

LINE REF ELECTRICAL EQUIPMENT 2013 2014 2015 2016 2017 TOTAL1 11-26 Infrastructure Replacements 7,060 6,000 26,000 6,965 6,200 52,225 2 27-30 Region Automation Projects 8,700 4,773 2,800 2,800 300 19,373 3 33-38 Transformer Replacements 1,500 1,665 3,050 2,500 2,340 11,055 4 40-47 Branch Circuit, Control & Relay Projects 5,625 1,200 650 3,250 2,950 13,675 5 49-53 Circuit Protection Equipment 400 150 150 2,565 - 3,265 6 54-56 Major Electrical Projects 1,500 2,500 2,750 6,000 6,000 18,750 7 59-70 Electrical Equipment - Miscellaneous 50 1,275 2,080 1,780 2,750 7,935 8 (Nominal Values are in $1000's) Total 24,835 17,563 37,480 25,860 20,540 126,277

A. Infrastructure Replacements 15

Transmission substations are generally maintained by SCE’s Transmission and Distribution 16

division. However, the substations in the Inyo and Mono County areas are maintained by SCE Hydro 17

due to their remote locations and proximity to Hydro powerhouses. These substations operate utilizing 18

12kV, 33kV, 55kV, and 115kV circuit breakers and associated equipment. Additional circuit protection 19

equipment with similar voltages is included in this section. The 2013-2017 capital expenditure forecast 20

for infrastructure replacement is $52.225 million, as shown in Table III-5 below. 21

23

Table III-5 Infrastructure Projects

(Nominal $)

LINE REF WBS Element Infrastructure Replacements 2013 2014 2015 2016 2017 TOTAL1 11 CG0-00-PP-HE-000074 Mt. Tom Substation 360 - - - - 360 2 12 CG0-00-PP-HE-000091 White Mountain Substation 1,000 - - - - 1,000 3 13 CG0-00-PP-HE-000057 Lee Vining Substation 400 2,250 20,000 - - 22,650 4 14 CG0-00-PP-HE-000058 Minaret Substation - 250 3,000 250 - 3,500 5 15 CG0-00-PP-HE-000055 Casa Diablo Substation - 1,000 1,600 2,000 - 4,600 6 16 CG0-00-PP-HE-000070 Control Station - 1,000 - - - 1,000 7 17 CG0-00-PP-HE-000070 Inyo Substation - - 150 - - 150 8 18 CG0-00-PP-HE-000070 Skiland Substation - - 150 - - 150 9 19 CG0-00-PP-HE-000070 Magmagen Substation - - 100 1,000 100 1,200

10 20 CG0-00-PP-HE-000070 Deep Springs Substation - - - 15 800 815 11 21 CG0-00-PP-HE-000070 Bridgeport Substation - - - 50 1,000 1,050 12 22 CG0-00-PP-HE-000070 Zack Substation - - - 500 - 500 13 23 CG0-00-PP-HE-000070 Sherwin Substation - - - 150 1,000 1,150 14 24 CG0-00-PP-HN-000038 Northern Hydro Replace 12KV Substations - - - 3,000 3,300 6,300 15 25 CG0-00-PP-HN-000010 Big Creek 3 Replace 12 KV Substation 5,300 - - - - 5,300 16 26 CG0-00-PP-HN-000038 Timberwine 12KV Substation - 1,500 1,000 - - 2,500 17 (Nominal Values are in $1000's) Total 7,060 6,000 26,000 6,965 6,200 52,225

1. Eastern Hydro Substation Infrastructure Projects 1

The Eastern Hydro Division (EHD) includes 13 substation infrastructure replacements. 2

The circuit breakers, switches, and transformers in these substations have been in continuous use at the 3

substation locations for 32 to 86 years and have reached the end of their reliable lives. The replacement 4

circuit breakers are expected to have a 30 year reliable service life. The capital forecast for these 13 5

projects is $38.125 million for 2013-2017. (Ref. 11-23) 6

a) Background 7

The equipment at White Mountain Substation is 57 years old, which is beyond its 8

expected life and not built to current SCE standards. The station is vital to radio communications for 9

emergency services in the Inyo/Mono counties area. These radio communications serve the emergency 10

services for SCE, DWP, and local radio as well. (Ref. 12) 11

The infrastructure replacement for Lee Vining Substation entails the complete 12

refurbishment of the substation in its existing location. This work will require construction of a 13

temporary substation to enable replacing equipment in the existing footprint. The existing equipment, 14

built in the early 1900’s, is well beyond its expected life and requires refurbishment. This project was 15

initially presented in SCE’s 2012 GRC (D.12-11-051, pages 61-62), where the Commission rejected 16

SCE’s plan to relocate the substation to a new location. That plan proved cost prohibitive and 17

refurbishment in its present location is now the least-cost option. (Ref. 13) 18

24

The Minaret Substation has equipment/devices that are at, or past, the end of their 1

expected life. The projects main focus will be the replacement of old 12Kv Oil Circuit Breakers with 2

new Vacuum Circuit Breakers, two 10.5 MVA Transformer Banks, and Primary and Secondary Bank 3

Breakers. Additionally, a new switchgear building enclosure to house the new M/C switchgear and 4

repair of existing concrete foundations will be performed. (Ref. 14) 5

Casa Diablo Substation was constructed and expanded from 1964 through 1974 6

with most of its current equipment installed during that time period, which indicates that the equipment 7

is past expected life. In addition, some equipment was salvaged from other SCE substations that date 8

back to the early 1950's for use at Casa Diablo Substation. This station resides on U.S. Forest Service 9

property by permit, which would benefit from the reduction of oil containing equipment replaced with 10

either SF-6 gas insulated or vacuum insulated circuit breakers and other apparatus. New digital 11

protective relay systems will improve the station reliability and add fault data capabilities along with 12

more accurate metering abilities. (Ref. 15) 13

Control Substation is now over 50 years in age and its equipment is exhibiting 14

increased needs for repair and maintenance in order to retain its required reliability. Also, the lack of 15

flexibility in its configuration results in less than desirable operating processes. The substation is also in 16

need of an upgrade to its grounding system in order to properly protect the station equipment. (Ref. 16) 17

The existing Magmagen Substation is a single bus configuration that requires 18

outages in the town of Mammoth Lakes whenever the equipment needs to be serviced or when repairs 19

due to an equipment breakdown occur. When this station is out of service, the power generated by the 20

Magmagen Power Plant has no outlet to the SCE system. (Ref. 19) 21

Bridgeport Substation is approaching its expected life of 30 years and its 22

equipment will need to be updated or replaced based on an inspection survey planned as a part of this 23

project. The wooden pole structures will also be inspected for an assessment of their effect on future 24

reliability of the substation. (Ref. 21) 25

Sherwin Substation is approaching its expected life of 30 years and its equipment 26

will need to be updated or replaced based on an inspection survey planned as a part of this project. The 27

wooden pole structures will also be inspected for an assessment of their effect on future reliability of the 28

substation. (Ref. 23) 29

25

b) Projects Scope 1

The Lee Vining project is an infrastructure replacement project that includes civil 2

work for foundations and cable trenches as required for a new control building and other steel structures 3

necessary for equipment as well as pads for the transformers that will be installed. A ring bus 4

configuration will be a basis for the design of the new substation so as to better handle the various lines 5

and voltages served by the substation. A new bus position for an as yet unnamed 16kV line will also be 6

installed as a part of this project. The project will also include the installation of required protection and 7

auxiliary station equipment. (Ref. 13) 8

For the remaining 12 projects, the individual scopes of each project vary based on 9

inspection surveys of each substation. However, all of the scopes involve installation of updated 10

transformers, circuit breakers, disconnect switches, relays, and associated control and protective 11

equipment. Engineering and procurement activities, as required for each of the substation scopes as 12

determined from the inspections, are included in these costs. In the case of the Control and Mt. Tom 13

substations, new or expanded control enclosures are being provided. At the Magmagen substation, in 14

addition to the equipment upgrades, the cable trench covers currently made of wood will be replaced 15

with fiberglass covers to minimize the water collection problems in those trenches, which can 16

undermine station foundations if allowed to persist for extended periods of time. In each substation the 17

project will include inspection and repair as necessary of foundations, cable trenches, and covers. 18

(Ref.11-23) 19

c) Projects Justification and Benefit 20

The justification for each of the projects described above is very similar. All of 21

these substations include obsolete equipment, which requires ever increasing levels of maintenance. In 22

the frequent cases where replacement parts are not available, they must be specially fabricated, which 23

increases the cost and the length of outages. The newly installed equipment will provide a higher degree 24

of reliability since the digital relays and micro-processors are less prone to failure than the existing 25

electro-mechanical devices. 26

The existing Lee Vining substation is a single bus configuration that requires an 27

outage for the town of Lee Vining any time equipment servicing is necessary. The existing Magmagen 28

substation is a single bus configuration that also requires an outage for the town of Mammoth any time 29

equipment servicing is necessary. The new substations will be built in such a manner (ring bus 30

configuration) to eliminate the necessity of customer outages for equipment service. 31

26

Replacement of the substations will enable the Project Development Division 1

(PPD) to maintain reliability and safety in the selected locations. The substations requiring replacement 2

are located in the Inyo and Mono Counties and are maintained by Eastern Hydro. In addition to 3

servicing the local generating plants from SCE Hydro, DWP, and Sierra Pacific, these substations also 4

provide local support for electrical power used by the communities of Bishop, Mammoth Lakes, June 5

Lake, Bridgeport, as well as others in the two counties. The justification for replacement of the 6

substations is to maintain reliable protection and connection of the local distribution system for service 7

to customers in the regional area. When there is no connection to the power grid to the south, these 8

substations provide the only energy source to the local communities. 9

2. Northern Hydro Substation Infrastructure Projects 10

Most of the Big Creek medium and low voltage substations are very old and have 11

reached the end of their expected lives. There are serious concerns about their reliability in providing 12

station service and other vital generation-related control, monitoring and protection functions. 13

Substation equipment has become obsolete and non-standard, and keeping these substations functional 14

has been increasingly difficult and more costly. The capital expenditure forecast is $14.100 million for 15

2013-2017. (Ref. 24-26) 16

a) Background 17

The Northern Hydro Division (NHD) substations are interconnected with 12kV 18

and 33kV distribution systems to provide alternate means of supplying loads and in some cases bringing 19

generation to the 220kVgrid. These distribution systems also serve local customers. Over the years, as 20

customer load has grown, substations that were originally solely intended for power generation purposes 21

with occasional customers now double as the main sources of power for an ever increasing number of 22

customers. Circuits leading to customers have become indirect, and this has made switching much more 23

complex. In addition to the advanced age of these substations, many of them are located near 24

waterways. Catastrophic failures which are increasing in their likelihood with this aged equipment will 25

not only cause service reliability problems, but they may also result in environmental damage. 26

b) Projects Scope 27

The Northern Hydro Replace 12kv Substation project covers all of the low 28

voltage substations in the NHD during 2013-2017, other than the two identified above, that are involved 29

in providing service to powerhouses, gates, penstocks/tunnels, communications stations, and other vital 30

generation related facilities. This project will also include the distribution system and customer 31

27

substations fed by this system. The focus of this project is to bring the low and medium voltage 1

substations and their service facilities up to current standards on a scheduled basis. The project includes 2

Upper, Mid, and Lower Canyon substations at Big Creek. The work is planned to cover nine sites 3

through the 2013-2017 period. (Ref. 24) 4

The Big Creek 3 Replace12kv Substation project includes the engineering, 5

procurement, construction, and testing required to replace the major equipment in the substation with 6

contemporary equipment. This will decrease the maintenance needs and increase the service reliability 7

of the substation. (Ref. 25) 8

The Timberwine 12kv Substation located at Eastwood has the same aging and 9

obsolete equipment problems as described above for the Big Creek 3 Substation. (Ref. 26) 10

c) Project Justification and Benefit 11

The justification for each of the projects described above is the same. All of these 12

stations include old and obsolete equipment that require ever increasing levels of maintenance. In the 13

frequent cases where replacement parts are not available, they must be specially fabricated, which 14

increases the length of outages and also increases the cost of the repairs. The benefits of doing this work 15

include increasing the overall reliability of the Big Creek generating system, as well as improving the 16

service reliability to customers now dependent on this system for their power supply in this remote area. 17

B. Region Automation Projects 18

The existing Hydro automation systems require replacement to keep pace with current and future 19

demands of the system. Following replacement, the new automation system will provide vital 20

information required for operations, work management planning, preventative maintenance, regulatory 21

compliance, and other needs that cannot be conveyed with the existing communication system. This 22

data can be captured, transmitted, and retained with the planned automation upgrades. The capital 23

expenditure forecast for these four projects is $19.373 million for 2013-2017. Table III-6 below 24

identifies the automation projects and the cost for each replacement. 25

Table III-6 Region Automation Projects

(Nominal $) LINE REF WBS Element Region Automation Projects 2013 2014 2015 2016 2017 TOTAL

1 27 CG0-00-PP-HE-000112 Kaweah - Automation Upgrade 5,700 - - - - 5,700 2 28 CG0-00-PP-HE-000104 Kern River - Automation Upgrade 2,200 2,000 - - - 4,200 3 29 CG0-00-PP-HE-000097 East End - Automation Upgrade 500 2,473 2,500 2,500 - 7,973 4 30 CG0-00-PP-HN-000081 Northern Hydro Automation Upgrades 300 300 300 300 300 1,500 5 (Nominal Values are in $1000's) Total 8,700 4,773 2,800 2,800 300 19,373

28

1. Background 1

The EHD is composed of four groups of plants located in Southern and Eastern 2

California. These groups are referred to as Kern River, East End, Kaweah and Bishop. Each grouping 3

contains a unique mixture of typical hydroelectric facilities such as dams, waterways, powerhouses, and 4

substations. Most of these facilities are not manned 24 hours a day on a year around basis. Currently 5

only the Kern River and Bishop groups are automated and they are controlled and monitored by the 6

Control Substation, which is the only facility manned on a 24-hour-a-day basis. This project will update 7

the equipment in those areas and it will also install complete systems in the two groups currently not 8

automated (Kaweah and East End). Upon completion, the Supervisory Control and Data Acquisition 9

(SCADA) will cover all of the facilities in the EHD. (Ref. 27-29) 10

The existing Ovation workstations within the NHD are over 15-20 years old and are 11

beginning to have problems, with six failures in 2012. The new workstations are redundant to the 12

existing workstations such that if an existing workstation fails the new workstation picks up the alarm 13

and point reporting duties so that Dispatch does not lose the powerhouse entirely. (Ref. 30) 14

2. Projects Scope 15

The Automation projects will deploy advanced data archiving, monitoring, reporting, and 16

remote diagnostics with secure, NERC Critical Infrastructure Protection (CIP)5 compliant software and 17

servers for viewing of Ovation screens, data, trending and reporting on the administration network. This 18

system will allow anyone with network access at Big Creek to look at any part of the Ovation system, 19

such as screens, points, and trends. It is NERC CIP compliant in that the server is locked down with 20

only the ability to read data. New Ovation workstations will be located at BC1, BC22A, BC3, BC8, 21

MMPH, BC4, Portal, and Dam 7. This includes software and installation to add new workstations to 22

existing Ovation systems for reliability and to be ready for the Enterprise Data Server (EDS) system. 23

The project will consist of (1) performing an engineering analysis; (2) procurement and 24

installation; and (3) testing of the SCADA system. The scope includes contracting for the development 25

of computer programming and screen graphics that allow personnel to see and control all SCADA 26

hardware. Final integration and testing of the facility equipment contracted in order to ensure overall 27

automation coordination. The system will consist of servers, man machine interfaces, Programmable 28

Logic Controllers (PLCs), communications systems, data logging equipment and sensing equipment as 29

suitable for each location in EHD. 30

5 See NERC Critical Infrastructure Protection (CIP) Version 5 Policy section in SCE-09 Chapter VIII.

29

3. Project Justification and Benefit 1

Replacing the aged equipment currently in use and adding the new equipment necessary 2

for those areas currently not automated will allow remote monitoring and control of Hydro facilities. 3

This automation will enable Hydro to meet new mandates from FERC and other governmental entities 4

to monitor water release capabilities and also maintain dam surveillance. The overall benefit will be 5

increased water control, system reliability, and regulatory compliance. The Dam sites are particularly 6

important because they are points for mandated FERC Instream Releases critical to FERC license 7

compliance. 8

C. Transformer Replacements 9

SCE Hydro utilizes Voltage Transformers in a variety of applications and locations. Step-up 10

transformers are used to increase voltage, usually from generation units or powerhouses to the higher 11

voltage used in transmission lines. Step-down transformers are used to decrease voltage, usually from 12

generator, powerhouse, or distribution system voltages for station light and power or other purposes. 13

Many of the transformers are used in switchyard locations that support the Transmission and 14

Distribution grid. The capital estimate for the nine planned transformer replacement projects is $11.055 15

million for 2013-2017. Table III-7 below provides the list of transformer projects and the cost for each 16

replacement. 17

Table III-7 Transformer Replacements

(Nominal $)

LINE REF WBS Element Transformer Replacements 2013 2014 2015 2016 2017 TOTAL1 33 CG0-00-PP-HE-000023 Bishop 2 - Replace #3 Transformer Bank - 200 1,000 - - 1,200 2 34 CG0-00-PP-HE-000023 Bishop 5 - Replace #1 Transformer Bank - 950 50 - - 1,000 3 35 CG0-00-PP-HE-000023 Kern River 3 - Replace Local Service Banks - - - 500 - 500 4 36 CG0-00-PP-HE-000023 Borel - Replace 3 Phase Station Light & Power Bank - - - - 40 40 5 37 CG0-00-PP-HN-000037 Northern Hydro Transformer Replacements - 515 2,000 2,000 2,300 6,815 6 38 CG0-00-PP-HN-000058 Portal Main Bank Transformer 1,500 1,500 7 (Nominal Values are in $1000's) Total 1,500 1,665 3,050 2,500 2,340 11,055

1. Background 18

Many of the transformers requiring replacement have been in continuous service for 50 19

years, with some 70 years old. These transformers have reached the ends of their useful lives and must 20

be replaced for reliability and safety. Dissolved Gas (in oil) Analysis (DGA) is used as an industry 21

benchmark to assess transformer winding condition. Significant increases in gassing levels and 22

dielectric degradation, which, inherent with the transformer’s age, indicate a high risk of failure. A fault 23

in the electrical system could trigger catastrophic failure of a degraded transformer, resulting in fire, 24

30

damage to neighboring equipment, release of hazardous materials, or injury to personnel. Replacement 1

of transformers is part of PPD’s program to methodically monitor old-age equipment and prioritize 2

replacement. The transformers that have DGA levels indicating deterioration and degradation beyond 3

repair will be replaced. 4

2. Projects Scope 5

Many of the older large transformers utilized individual transformers for each phase of 6

power. Most of the new transformers will utilize modern three-phase transformers. The project's scope 7

will include preliminary and detailed engineering, foundation assessment and improvement. (Ref. 33-8

38) 9


Safety, environmental considerations, and operational reliability are the prime factors 11

considered in replacing transformers that are beyond their useful life. A catastrophic failure of a 12

degraded transformer could result in fire, damage neighboring equipment, release hazardous materials, 13

and/or injure personnel. Many of the transformers are in close proximity to historic stream channels 14

with flowing water. A failure could entail severe environmental consequences. In addition, there are 15

also economic benefits to replacing transformers before they fail in-service. An unexpected failure in-16

service will have a greater cost than a planned replacement due to loss of generation during the 17

procurement and planning phases of work. These transformers typically have lead times greater than 18

one year and in some cases up to two years. Economic analyses have been performed demonstrating the 19

economic benefits of replacements. 20

D. Branch Circuit, Control, and Relay Panels 21

Hydro operations uses panels for branch circuit protection and distribution, protective relays, and 22

other uses. There is one project that requires replacement of a branch circuit panel and three projects 23

that require replacement of protective relay panels. Replacement of these aging panels will ensure 24

protection to powerhouse components, generators, and the safety of operating personnel. The capital 25

forecast for these eight projects is $13.675 million for 2013-2017. Table III-8 below is a list of the eight 26

projects and the cost for each replacement. 27

31

Table III-8 Branch Circuit, Control and Relay Panels

(Nominal $) LINE REF WBS Element Branch Circuit, Control & Relay Projects 2013 2014 2015 2016 2017 TOTAL

1 40 CG0-00-PP-HE-000067 Poole - Replace Unit Breaker/ Station Light & Power 4,200 150 - - - 4,350 2 41 CG0-00-PP-HE-000072 Bishop 4 - AC Relay Protection/Excitation/Unit Breakers 1,258 150 - - - 1,408 3 42 CG0-00-PP-HE-000048 Rush Creek - Replace Relay Protection/AC Panels 67 - - - - 67 4 43 CG0-00-PP-HE-000024 Bishop 2 - Station Electrical Upgrade - - 250 3,000 - 3,250 5 44 CG0-00-PP-HE-000024 Bishop 3 - Unit Breaker/Relay Protection - - 250 100 2,000 2,350 6 45 CG0-00-PP-HE-000024 Kern River 3 - Replace Protective Relay Panels - 750 - - - 750 7 46 CG0-00-PP-HE-000024 Borel - Replace Control & Relay Panels - - - - 800 800 8 47 CG0-00-PP-HN-000057 Northern Hydro Backcountry Instrumentation 100 150 150 150 150 700 9 (Nominal Values are in $1000's) Total 5,625 1,200 650 3,250 2,950 13,675

1. Background 1

The Poole Powerplant was placed into service in approximately 1925. Many of its major 2

components are still in service including the indoor 7kV bussing, 7kV switching disconnects, 7kV 3

instrument transformers, 7kV unit circuit breaker, and the station light and power system. These 4

components are original equipment and have outlived their expected lives, nearing failure and are 5

obsolete. The control room's relays, controls, and meters have also reached the end of their expected 6

lives, with most of these components installed between 1950 and 1985. 7

Bishop Plant 4 equipment has performed well beyond its expected life. If failure occurs 8

current SPCC configuration will be barely adequate due to proximity to water. Replacement will 9

improve reliability and improve the current SPCC configuration to reduce environmental risks 10

associated with proximity to water. 11

Bishop Creek Plant 2 was constructed in 1908. The station light and power system is the 12

original equipment and needs to be completely replaced because it is well beyond its expected lifespan. 13

Other equipment in the plant was updated in the 1950s and 1960s, but it is now its expected life, is 14

obsolete and needs to be replaced. 15

At Bishop Creek Plant 3 the unit breakers and associated relays are very old and are 16

considerably beyond their originally expected life span. Also, these breakers are contained in a 17

relatively confined space, which could cause a personnel safety problem if a failure were to occur. The 18

new breakers would decrease the safety risk and the new relay protection for the breakers would 19

enhance the overall reliability of the station. 20

The Northern Hydro Division has multiple Generator Relays that are in need of 21

replacement. The units are equipped with a protection system that is obsolete and maintenance-prone. 22

32

Most of them are the electromechanical type, which were the original equipment installed with the units. 1

New relays would decrease maintenance costs and enhance the overall reliability of the station. 2

2. Projects Scope 3

The Poole Powerplant upgrade will improve plant safety by removing all 7kV bussing, 4

disconnects, transformers, and circuit breaker from the indoor mezzanine and placing these components 5

into metal-clad switchgear in a newly constructed addition to the plant building, reducing high voltage 6

exposure to personnel. The station light and power system will be replaced to meet current codes and 7

regulations and ensure fault current safety and correct equipment grounding. The new system will also 8

provide for any future electrical additions. The SPCC oil containment in the switch yard will be 9

improved so that the No. 1 Bank will not be affected by icing build up, and the other oil containing 10

equipment will be completely contained. The additional building space will afford safe operation and 11

maintenance of the high voltage circuit breaker and metal-clad switchgear. These upgrades will result in 12

improved safety, reliability, and environmental compliance. (Ref. 40) 13

The Bishop Creek 4 upgrade includes: (1) the removal/abandonment of equipment 14

(transformers, panels and associated electrical gear) in Vault No. 1; (2) replacing and rerouting feeder 15

cables from Vault No. 1 to new Switchgear mounted on the concrete pad above Vault No. 1; (3) 16

installation of an overhead raceway from the top of the Switchgear into Plant 4; (4) installation of a new 17

temporary 2400 volt supply cable from the 2400 volt Station Bus to the Switchgear, and; (5) rerouting of 18

the shop feeder to the new Switchgear via the overhead raceway, and (6) replacement of Vault No. 2 19

equipment, transformers, panels and associated electrical gear, with a pole mounted transformer and 20

distribution panel. (Ref. 41) 21

At Bishop Creek 2 the station light and power system including the main switchboard, 22

sub-panels, and wiring will be re-engineered and replaced. The control room panels will be replaced 23

with modern racks containing new digital relays, meters, controls, switches, and transducers. The three 24

2.4kv oil circuit breakers will be replaced with 17kV class gas breakers. Engineering and procurement 25

activities for the upgraded control room are included. (Ref. 43) 26

The project at Bishop Creek 3 Northern Hydro includes the design engineering and 27

equipment procurement necessary to replace all of the unit breakers and relay protection within the 28

station. It also includes monies for installation of the new equipment by SCE personnel. (Ref. 44) 29

33


For each of the projects in this category, the replacement of very old equipment, which 2

potentially compromises the reliability of various parts of the system, is involved. Wherever possible 3

these projects will replace oil filled equipment, which could pose an environmental problem, with 4

modern equipment that minimizes the environmental exposure. In the case of one of the projects a 5

potential safety exposure for personnel is minimized when compared to the current installation. In 6

addition to these above factors, there are also economic benefits to replacing the equipment before they 7

fail in-service. An unexpected failure in service will have a longer outage due to the lead time required 8

for engineering and procurement, which would result in greater costs for replacement power. 9

E. Circuit Protection Equipment 10

Generator unit circuit breakers provide protection and isolation for Hydro generating units from 11

local switchyards and the distribution system grid. This protection will enable the generator to trip (shut 12

down) if problems are detected in the transmission system or within the generator itself. The capital 13

forecast for these five projects is $3.265 million for 2013-2017. Table III-9 below show a list of the five 14


Table III-9 Circuit Protection Equipment

(Nominal $) LINE REF WBS Element Circuit Protection Equipment 2013 2014 2015 2016 2017 TOTAL

1 49 CG0-00-PP-HE-000075 Ontario 1 Replace Circuit Breakers 400 - - - - 400 2 50 CG0-00-PP-HE-000022 Tule - Replace 66kv Circuit Breakers - 150 - - - 150 3 51 CG0-00-PP-HE-000022 Kaweah 3 - Replace 66kv Circuit Breakers - - 150 - - 150 4 52 CG0-00-PP-HE-000019 Kern River 3 - Replace 2.4kV Circuit Breakers - - - 500 - 500 5 53 CG0-00-PP-HE-000022 Kern River 3 - Replace 66kV Circuit Breakers - - - 2,065 - 2,065 6 (Nominal Values are in $1000's) Total 400 150 150 2,565 - 3,265

1. Background 16

The circuit breakers at Kern River 3 are the original powerhouse equipment and are 17

approximately 75 years old. They are almost completely worn out and spare parts are no longer 18

available so all replacement parts are currently being cannibalized from out of service exciter circuit 19

breakers of the same vintage. The current breakers contain oil and they need to be replaced with air 20

magnetic breakers to reduce the exposure to the environment of having oil breakers in the plant. 21


The Kern River 3 circuit breaker replacement projects involve engineering, procurement 23

and installation of new 2.4kV and 66kV circuit breakers. In each case the condition of the mounting 24

34

pads will be investigated for their ability to serve safely over the life of the new breakers and they will 1

be re-engineered if there is any doubt as to their ability to provide stability as required. All of the new 2

breakers to be procured are anticipated to be gas filled breakers. (Ref. 52-53) 3


These breakers must perform reliably in order to maintain station power for generation 5

and transmission operations. They are outdated, and their reliability is below current SCE system 6

standards that results in a plant outage when switching to a local service bus in order to resume 7

operations. This new equipment will return the station reliability to SCE system standards. 8

The justification for the Kern River project is the replacement of obsolete equipment in 9

order to gain greater reliability of those systems. That is, the new equipment will decrease the 10

likelihood of outages within the system which in some cases could extend for unacceptable lengths of 11

time. Removal of a large number of oil filled pieces of equipment from the stations will serve to lessen 12

the potential of an environmental problem in the case of a failure. 13

F. Major Electrical Projects 14

The Major Electrical Projects category consists of three capital projects that exceed $3 million 15

dollars and were not easily categorized into the aforementioned electrical categories. The capital 16

forecast for these three projects is $18.750 million for 2013-2017. Table III-10 below lists the three 17


Table III-10 Major Electrical Projects

(Nominal $) LINE REF WBS Element Major Electrical Projects 2013 2014 2015 2016 2017 TOTAL

1 54 CG0-00-PP-HE-000081 Bishop - Communication Fiber 400 500 2,500 - - 3,400 2 55 CG0-00-PP-HE-000020 Agnew - Replace 4KV Transformers and Transmission Line 1,000 2,000 250 - - 3,250 3 56 CG0-00-PP-HN-000036 Huntington Lake Dam 1 Replace Power & Controls 100 6,000 6,000 12,100 4 (Nominal Values are in $1000's) Total 1,500 2,500 2,750 6,000 6,000 18,750

1. Background 19

The Bishop Communication Fiber optic project will extend the communication fiber 20

optic cable from the Control Substation to Bishop Plant 2, Plant 3, Intake 2, South fork diversion, South 21

Lake, and Sabrina Lake. This project will be performed in six phases, connecting each location one at a 22

time. 23

35

The 4kV line system feeding the Gem and Agnew reservoirs has been in service for at 1

least 80 years. It was originally installed in 1928-1930. The transformers have been in service since the 2

original installation date and could possibly contain Polychlorinated Biphenyl, which is unknown at this 3

time. The likelihood of transformer failure has increased greatly due to age. Several of these 4

transformers reside on the dams and in the proximity of the waterways, and any oil spillage would have 5

a negative environmental effect. The lines do not conform to SCE Rule 20, NEC NFPA 70, and IEEE 6

NESC codes governing electrical conductor clearances and pose a significant contact risk to the general 7

public. In addition, the 4kV and related 2.4kV voltage class equipment is obsolete in the SCE system, 8

and it is becoming very difficult to obtain replacement materials. The replacement Agnew line and 9

transformers will be constructed to the current SCE Distribution 12kV class. This upgrade in voltage 10

will also eliminate operational problems experienced currently. 11

Huntington Lake supplies water to BC1 Powerhouse using series of dams, gatehouses, 12

flow lines, and penstock valves. Some of these components are also part of the power and control 13

protection system required to protect plant workers and the public in the event of a penstock failure or a 14

failure of a high pressure component in the powerhouse. These components are currently powered from 15

a single power source, with deteriorating cables connecting them, and an old emergency generator as a 16

backup power source. The emergency generator is over 50 years old and unreliable, and replacement 17

parts are difficult to find. The power cable connecting the components has deteriorated to the point that 18

several sections are no longer used. 19


The Bishop Communication Fiber project includes extending the communication fiber 21

optic cable from Control Substation to Bishop Plant 2, Plant 3, Intake 2, South fork diversion, South 22

Lake, and Sabrina Lake. This project will be done in phases. The first phase will be to install fiber from 23

the Control Substation to Plant 2 on the Plant 2 55kV line.. The second phase will be to run fiber optic 24

cable from Control Substation to Plant 3 on the Plant 3 and 4 115kV line. The third phase will be to run 25

cable from Plant 2 to Intake 2 on the Sabrina 12kV line. The fourth phase will be to install cable from 26

Intake 2 to South Fork Diversion on the Sabrina 12kV line. The fifth will be to run cable from South 27

Fork Diversion to South Lake to be installed on the existing Verizon communication line to South Lake. 28

And, finally, the sixth phase will be to run fiber optic cable from Intake to Sabrina Lake on the Sabrina 29

12kV line. (Ref. 54) 30

36

The 4kV line system feeding the Gem and Agnew reservoirs will buried in a conduit 1

under Agnew tramway. The poles will include a mounting provision for future fiber-optic cable 2

installation. SCE plans to install new conductors and transformers where existing units reside. The 3

new line shall be supplied from an existing 12kV distribution line near the Rush Creek powerplant. (Ref. 4

55) 5

To resolve the obsolescence, reliability, and safety concerns of the existing Power and 6

Control System of the Huntington Lake existing system, SCE performed preliminary engineering and 7

evaluated several alternatives. SCE believes that the most reliable approach would be to construct a new 8

12kV line partially underbuilt on the existing 33kV line up to Camp Ten Substation and balance 9

overbuilt on 7kV Grouse line - light duty steel poles - with use of aerial cable. The implementation 10

efforts include detailed engineering, permits, procurement, construction, startup, and turnover 11

documentation. (Ref. 56) 12

3. Projects Justification and Benefit 13

Bishop Creek Communication Fiber project is required due to the unreliability of the 14

existing telecommunication pathways from the Control Substation to Plants 2 and 3. High speed 15

protection via transfer trip would be improved as the existing equipment does not allow for the data 16

capacity for video monitoring of the upper lakes. Ground return to the station during line outages will 17

improve the safety of personnel and equipment. This project also addresses public safety concerns and 18

decreases the negative impacts on customers in the local area that are currently exposed to outages that 19

can be traced to problems with the grounding system in the Control Substation. 20

The Gem and Agnew 4kV line needs to be improved due to low line sag clearances in 21

multiple locations. New lines will ensure compliance with all current SCE safety standards. Removal 22

of old oil containing units with possible PCB content will ensure environmental compliance. New 23

transformer units will not contain any PCBs and will have a reset service lifespan. The 80-year old 24

equipment is nearing eventual age-related failures, and replacement equipment will relieve this concern. 25

The Huntington Lake power and control system is old and obsolete, and it requires 26

frequent maintenance, electrician support, and test tech support. The existing 7kV incline line and poses 27

a reliability and public safety concern. This project will minimize these concerns. 28

G. Electrical Equipment – Miscellaneous Projects 29

The Electrical Equipment Miscellaneous Projects include a wide variety of work. Small projects 30

for control systems, transformers, circuit protection, automation, and instrumentation are discussed here, 31

37

whereas the larger projects of these types have been discussed in previous sections. The various 1

miscellaneous equipment that have not been discussed in previous sections includes emergency 2

generators, station batteries, relays, power disconnects, fault recorders, low voltage switchgear, as well 3

as other projects. The capital forecast for these 12 projects is $7.935 million for 2013-2017. Table III-4

11 below shows a list of the projects and the cost for each replacement. 5

Table III-11 Electrical Equipment – Miscellaneous Projects

(Nominal $)

LINE REF WBS Element Electrical Equipment - Miscellaneous 2013 2014 2015 2016 2017 TOTAL1 59 CG0-00-PP-HE-000005 Santa Ana River 1 - Water Controllers - 50 - - - 50 2 60 CG0-00-PP-HE-000005 Fontana - Replace/Upgrade Unit Breakers - - 200 - - 200 3 61 CG0-00-PP-HE-000005 Santa Ana River 1 - Replace Switchyard Breakers - - 30 - 950 980 4 62 CG0-00-PP-HE-000005 Sierra - Water Controllers - - 50 - - 50 5 63 CG0-00-PP-HE-000005 Ontario - Water Controllers - - 50 - - 50 6 64 CG0-00-PP-HE-000005 Santa Ana River 3 - Replace Switchyard Breakers - - - 30 - 30 7 65 CG0-00-PP-HE-000005 Borel Replace 2.4kV Busswork - - - - 100 100 8 66 CG0-00-PP-HN-000023 Big Creek 4 Low Voltage Switchgear - 50 250 - - 300 9 67 CG0-00-PP-HN-000023 Big Creek 4 ISO Bus Replacement Unit 1 & 2 - 50 - 250 - 300

10 68 CG0-00-PP-HN-000023 Big Creek 3 Circuit Breaker Replacement - 50 250 - - 300 11 69 CG0-00-PP-HN-000024 Eastwood PowerStation Pony Motor - 75 250 0 - 325 12 70 CG0-00-PP-HN-000023 Northern Hydro Miscellaneous Electrical 50 1,000 1,000 1,500 1,700 5,250 13 (Nominal Values are in $1000's) Total 50 1,275 2,080 1,780 2,750 7,935

1. Background 6

The projects in this category provide for replacement of aging equipment in the system. 7

Most of the equipment is in excess of 50 years old and has surpassed their original expected life and 8

hence is a continuing source of outages that affect system reliability. There are also safety 9

considerations in some of the locations due to not only the age of the equipment, but also the manner in 10

which the current equipment is installed. 11

2. Project Scope 12

This category includes projects that are needed on the system due to replacement of aging 13

equipment, which in some cases may be as much as 80 years old and the upgrading of equipment for 14

reliability and safety reasons. The projects include a wide variety of work such as small projects for 15

control systems, transformers, circuit protection, automation, and instrumentation. In addition this 16

category contains miscellaneous equipment that was not discussed in previous sections including 17

emergency generators; station batteries; relays; power disconnects; fault recorders; low voltage 18

switchgear; as well as other miscellaneous materials. (Ref. 59-70) 19

38


The benefits of these 12 projects vary, but, in general, the projects are needed to provide 2

reliable and safe operations for the Hydro operating equipment. All of the projects in this category 3

involve the replacement of very old equipment that compromises the reliability of various parts of the 4

Hydro Electrical system. In addition, the proposed projects will bring the equipment described in this 5

testimony up to current SCE system standards. The new equipment will decrease the likelihood of 6

outages within the system, which could extend for unacceptable lengths of time. 7

39

IV. 1

PRIME MOVERS 2

SCE Hydro operates 76 generating units at 35 powerhouses. Water turbines convert the flow of 3

high pressure water into rotary motion or mechanical energy, which the generators in turn convert into 4

electrical power. The high pressure water and rotary motion cause wear and tear on the turbine units. 5

The heat created by a generator when producing electrical power causes wear and tear on the generator 6

bearings and windings. If timely repairs are not performed when warranted, unit failure is inevitable. 7

Therefore, turbines and generators receive annual maintenance and inspections. They generally 8

will operate for several decades without major refurbishment. However, when they require 9

refurbishment, the size and specialized nature of the equipment generally results in projects exceeding 10

$100,000 for the Hydro units under 5MW, and often exceeding $1 million for the units larger than 5 11

MW. Additional Prime Mover projects include turbine shut-off valves, turbine runner or seal 12

replacement, wicket gates, and governor replacements. The Prime Movers capital forecast for Hydro is 13

$68.995 million for 2013-2017. The following Table IV-12 shows the major programs and projects for 14

the Prime Movers category. 15

Table IV-12 Prime Mover Major Programs & Projects

(Nominal $)

LINE REF PRIME MOVERS 2013 2014 2015 2016 2017 TOTAL1 74-91 Turbine Wicket Gates & Waterwheels 2,980 2,430 3,750 3,000 4,500 16,660 2 92-100 Generator Coils & Rewinds 2,015 2,450 2,500 2,450 3,000 12,415 3 101-106 Generator Excitation 600 - 50 - 475 1,125 4 107-113 Turbine Valves & High Pressure Piping 305 150 450 340 1,850 3,095 5 114 Prime Mover Replacements 950 1,500 9,000 14,600 3,250 29,300 6 116-127 Prime Movers Miscellaneous Projects 600 1,000 350 2,300 2,150 6,400 7 (Nominal Values are in $1000's) Total 9,463 9,544 18,115 24,706 17,242 68,995

A. Turbine Wicket Gates, Runners, and Repowers 16

SCE Hydro powerhouses operate with two types of turbines: 17

Francis (also known as reaction), which utilizes a series of curved wicket gates to control and 18

direct high pressure water to a runner that has vane type blades. 19

Pelton (also known as impulse), which utilizes one or more nozzles that control and direct 20

high pressure water to a series of buckets located on a “waterwheel.” 21

40

A complete refurbishment of the entire turbine is generally called a repower and is done on an 1

infrequent basis. Prior to a repower, there may be partial refurbishment projects to enhance efficiency or 2

replace deteriorated components. The Turbine Wicket Gates, Runners, and Repowers forecast for 3

Hydro projects is $16.660 million for 2013-2017. Table IV-13 below provides a list of the 17 projects 4

and the cost for each replacement. 5

Table IV-13 Turbine Wicket Gates, Runners, and Repowers

(Nominal $)

LINE REF WBS Element Turbine Wicket Gates & Waterwheels 2013 2014 2015 2016 2017 TOTAL1 74 CG0-00-PP-HE-000105 Kern River 1 Unit 2 - Turbine Refurbishment 2,100 - - - - 2,100 2 75 CG0-00-PP-HE-000087 Bishop 3 Unit 2 - Turbine Refurbishment 500 - - - - 500 3 76 CG0-00-PP-HE-000100 Mill Creek 3 Unit 5 - Turbine Replacement 300 - - - - 300 4 77 CG0-00-PP-HE-000101 Mill Creek 3 Unit 3 - Turbine Replacement 30 400 - - - 430 5 78 CG0-00-PP-HE-000095 Santa Ana River 1 Turbine Refurbishments 50 100 900 900 - 1,950 6 80 CG0-00-PP-HE-000042 Mill Creek 3 Unit 4 - Turbine Replacement - 30 400 - - 430 7 81 CG0-00-PP-HE-000042 Bishop 5 Unit 1 - Turbine Refurbishment - 400 - - - 400 8 82 CG0-00-PP-HE-000042 Kern River 1 Unit 1 - Turbine Refurbishment - 1,500 - - - 1,500 9 83 CG0-00-PP-HE-000042 Bishop 2 Unit 1 - Turbine Refurbishment - - 400 - - 400

10 84 CG0-00-PP-HE-000042 Bishop 3 Unit 1 - Turbine Refurbishment - - 400 - - 400 11 85 CG0-00-PP-HE-000042 Borel Unit 2 - Replace Wicket Gates & Runner Seals - - - - 50 50 12 86 CG0-00-PP-HE-000042 Kern River 1 Unit 3 - Turbine Refurbishment - - 1,500 - - 1,500 13 87 CG0-00-PP-HE-000042 Bishop 4 Unit 2 - Turbine Refurbishment - - - 400 - 400 14 88 CG0-00-PP-HE-000042 Kern River 1 Unit 4 - Turbine Refurbishment - - - 1,500 - 1,500 15 89 CG0-00-PP-HE-000042 Bishop 4 Unit 1 - Turbine Refurbishment - - - - 400 400 16 90 CG0-00-PP-HE-000042 Bishop 4 Unit 5 - Turbine Refurbishment - - - - 400 400 17 91 CG0-00-PP-HN-000040 Northern Hydro Wicket Gates & Runners - - 150 200 3,650 4,000 18 (Nominal Values are in $1000's) Total 2,980 2,430 3,750 3,000 4,500 16,660

1. Background 6

Turbine runners and wheels become worn and develop cracks from the force of the water. 7

cavitation and erosion accelerate the wear. Water with high amounts of suspended solids worsens the 8

erosion process. Where possible, repairs are often accomplished by grinding and welding with stainless 9

steel. However, over time, the wheels and runners can no longer be repaired and must be replaced. 10

Carbon steel wheels erode much faster than stainless steel and require significantly more repairs. 11

Replacement of waterwheels is often done with stainless steel to reduce the effects of cavitation and 12

erosion. 13

2. Project Scope 14

A typical project scope includes procurement of the necessary materials prior to the 15

project due to lead times, removal of the generator, removal of the head cover and disassembly of the 16

turbine, replacement of required equipment, repair of equipment, reassembly, and testing of the turbine. 17

(Ref. 74-91) 18

41


Project benefits for the Hydro turbines are to increase reliable and efficient operations 2

through refurbishment of worn components. This decreases the volume of water loss during operations. 3

The planned replacement of the turbine components will result in a significantly shorter outage period 4

compared to a forced outage due to the long lead time for waterwheels. In addition, there are also 5

economic benefits to replacing equipment before in-service failure. An unexpected failure in-service 6

will have a longer outage due to the lead time required for engineering and procurement, which would 7

result in greater costs for replacement power. Economic analyses have been performed demonstrating 8

the economic benefits of replacements. 9

B. Generator Coils and Rewinds 10

Hydro generators consist of the stationary stator with windings (half-coils) and the rotating field 11

with coils or poles. Due to the high power flows, stators require significantly more maintenance and 12

refurbishment than the rotating field. Rewinds indicate a total replacement of the stator half-coils, 13

which will return the generator to an efficient and reliable condition. Some projects also require 14

replacement of field poles. The capital forecast for the nine rewind projects is $12.415 million for 2013-15

2017. Table IV-14 is a list of the nine Generator Coil and Rewind projects and the cost for each 16

replacement. 17

Table IV-14 Generator Coils and Rewinds

(Nominal $)

LINE REF WBS Element Generator Coils & Rewinds 2013 2014 2015 2016 2017 TOTAL1 92 CG0-00-PP-HE-000041 Bishop 5 Unit 1 - Rewind Generator / Rotor - 450 - - - 450 2 93 CG0-00-PP-HE-000041 Bishop 2 Unit 1 - Rewind Stator / Rotor - - 450 - - 450 3 94 CG0-00-PP-HE-000041 Borel Unit 2 - Stator Rewind & Replace Leads - - - - 100 100 4 95 CG0-00-PP-HE-000041 Bishop 2 Unit 3 - Rewind Generator / Rotor - - - 450 - 450 5 96 CG0-00-PP-HE-000041 Bishop 2 Unit 2 - Rewind Stator / Rotor - - - - 450 450 6 97 CG0-00-PP-HE-000041 Lundy Unit 1 - Rewind Stator / Rotor - - - - 450 450 7 98 CG0-00-PP-HN-000063 Mammoth Pool Unit 1 Rewind & Field Poles 2,000 - - - - 2,000 8 99 CG0-00-PP-HN-000060 Big Creek 3 Unit 3 Rewind & Field Pole 15 - - - - 15 9 100 CG0-00-PP-HN-000026 Northern Hydro Generator Rewinds 2,000 2,050 2,000 2,000 8,050

10 (Nominal Values are in $1000's) Total 2,015 2,450 2,500 2,450 3,000 12,415

1. Background 18

Hydro generators are inspected on a periodic basis to assess the condition of their 19

windings. Over time the stresses from producing electrical power will cause deterioration of the 20

insulation that separates the individual coil components. Deteriorated insulation causes shorting of the 21

coils, thus reducing the efficiency of the generator. Further deterioration and shorts result in generator 22

42

failure. Temperature monitoring and testing can usually provide advance warning of a condition that 1

could result in generator failure. An unexpected generator failure can result in a sudden large electrical 2

short circuit of the generator while in service. Such an event could cause extensive damage to other 3

parts of the generator and possibly to other electrical equipment connected to the generator. 4

2. Project Scope 5

Generator windings normally have a six month minimum lead time, so planning is 6

essential for rewind outages. A typical rewind project includes costs to: 7

Disassemble the generator 8

Remove the stator windings 9

Unstack and restack the core iron if testing indicates problems 10

Rewind the stator 11

Replace field poles if necessary 12

Reassemble the generator (Ref. 92-100) 13


The project benefit from a rewind is to return the generating unit to a reliable and safe 15

operating condition. An unexpected generator failure can result in a sudden, large electrical short circuit 16

of the generator while in service. Such an event would cause extensive damage to other parts of the 17

generator and possibly to other electrical equipment connected to the generator. An unexpected failure 18

that occurs without the benefit of planning for replacement materials will result in much greater outage 19

duration. Economic analyses have been performed demonstrating the economic benefits of 20

replacements. 21

C. Generator Excitation Projects 22

Excitation equipment is vital to producing electrical power from a generation unit. The 23

relatively small excitation power provides current to the generator’s fields, so that the generator can in 24

turn produce a much larger amount of power output from the rotation of the turbine. The capital 25

expenditure forecast for the six planned excitation projects is $1.125 million for 2013-2017. Table IV-26

15 is a list of the six projects and the cost for each replacement. 27

43

Table IV-15 Generator Excitation Projects

(Nominal $)

LINE REF WBS Element Generator Excitation 2013 2014 2015 2016 2017 TOTAL1 101 CG0-00-PP-HE-000103 Borel - Install Solid State Exciters Units 1 & 2 300 - - - - 300 2 102 CG0-00-PP-HE-000103 Borel - Install Solid State Exciter Unit 3 - - - - 350 350 3 103 CG0-00-PP-HE-000071 Kern River 3 - Install Solid State Exciters - - 50 - - 50 4 104 CG0-00-PP-HE-000071 Kaweah 2 - Replace Excitation - - - - 125 125 5 105 CG0-00-PP-HN-000024 Big Creek 1 Unit 1 - Solid State Excitation 150 - - - - 150 6 106 CG0-00-PP-HN-000024 Big Creek 1 Unit 2 - Solid State Excitation 150 - - - - 150 7 (Nominal Values are in $1000's) Total 600 - 50 - 475 1,125

1. Background 1

The excitation equipment is obsolete and unreliable on many of the generation units in 2

Northern and Eastern Hydro. On many of the units, the existing exciter is a rotating type, which creates 3

the power from the rotating generator shaft. If the exciter is worn and cannot maintain balance, it affects 4

the balancing in the entire generator, causing generator bearing problems as well. The existing exciters, 5

some of which are over 80 years old, are obsolete and parts are no longer available. Therefore, many 6

repairs require significant out-of-service time while parts are reverse engineered, fabricated, installed, 7

and tested. 8

Grid reliability authorities such as CAISO, WECC, and NERC have been calling for 9

improvement of reactive power performance by use of Power System Stabilizers (PSS) to mitigate grid 10

instability problems. Bulk power grid performance can be enhanced with power system stabilizers 11

(PSS), but it does not make practical or economic sense to install new PSS components on the old, 12

outdated, and unreliable existing rotating exciters. Therefore, the existing system will be replaced with 13

Digital Static Excitation System. 14


The project scope for these projects is similar and includes engineering, new excitation 16

equipment, developing a specification, and going out to bid. Work includes removal of the existing 17

exciter equipment and the associated Field CB, rheostat, and voltage control system. The project scope 18

also involves the installation of the new solid state excitation cabinets, which will include power 19

potential transformers, DC rectifiers, a voltage control system, and the associated conduit and cable 20

trays. (Ref. 101-106) 21

44


Replacement of the obsolete excitation equipment with new Digital Static Excitation 2

Systems is necessary to improve reactive power performance in accordance with Grid Reliability 3

Authorities such as CAISO, WECC, and NERC and to mitigate grid instability problems. In addition to 4

meeting regulatory requirements and improving grid stability, the benefit of replacing the exciters before 5

they fail while in service includes the prevention of extended outages required for replacement of 6

obsolete parts. An exciter failure would likely require approximately three months additional outage 7

time than a planned replacement. 8

D. Turbine Valves and High Pressure Piping 9

Turbine Shut Off (TSO) valves and headers distribute and control the water that flows from a 10

penstock to a turbine. This allows individual turbines to be isolated for repairs, while others can remain 11

on-line. Upstream of the TSO valves is a penstock valve. This penstock valve works in conjunction 12

with the TSO valves to quickly shut off flow to all turbines during an emergency. The existing TSO 13

valves are in poor condition and do not fully shut off water to the units. 14

Big Creek powerhouses utilize high pressure water from penstocks to cool bearings and for other 15

purposes. The piping in powerhouses at Big Creek 3, Big Creek 4, and Mammoth Pool is virtually all 16

original installation material dating back as far as 1913. Recent leakage and repairs at Big Creek 1 and 17

Big Creek 2 have led to an investigation of other powerhouses. This investigation revealed that general 18

erosion and corrosion compromises Big Creek 3, Big Creek 4, and Big Creek 8 powerhouses as well. 19

High pressure piping has been completed at Big Creek 1 and Big Creek 2/2A, with the exception of the 20

800 psi pressure reducing station. Mammoth Pool indicates the need for replacement, but the erosion is 21

not as severe as the plants listed above. The thinning of the piping walls creates a tremendous safety 22

hazard and a risk for unplanned outages. 23

The capital forecast for these six projects is $3.095 million for 2013-2017. Table IV-16 is a list 24

of the six Turbine Valve and High Pressure Piping projects and the cost for each. 25

45

Table IV-16 Turbine Valves and High Pressure Piping Systems

(Nominal $)

LINE REF WBS Element Turbine Valves & High Pressure Piping 2013 2014 2015 2016 2017 TOTAL1 107 CG0-00-PP-HE-000108 Kern River 3 - Replace TSO Bypass Valves 155 - - - - 155 2 108 CG0-00-PP-HE-000031 Lytle Creek Units 1&2 Replace TSO Valve - - - 20 450 470 3 109 CG0-00-PP-HE-000031 Santa Ana River 1 Replace TSO Valves - - - 20 650 670 4 111 CG0-00-PP-HN-000079 Big Creek 4 High Pressure Piping 150 150 150 - - 450 5 112 CG0-00-PP-HN-000074 Big Creek 3 High Pressure Piping - - 150 150 150 450 6 113 CG0-00-PP-HN-000075 Big Creek 8 High Pressure Piping - - 150 150 600 900 7 (Nominal Values are in $1000's) Total 305 150 450 340 1,850 3,095

1. Background 1

TSO valves and headers distribute and control the water that flows from a penstock to a 2

turbine. This allows individual turbines to be isolated for repairs, while others can remain on-line. 3

Upstream of the TSO valves is a penstock valve. This penstock valve works in conjunction with the 4

TSO valves to quickly shut off flow to all turbines during an emergency. 5

The TSO valves at Big Creek are original design, some over 80 years old. They are often 6

used as a clearance boundary. If the TSO valve is a part of a unit clearance there is usually water at full 7

pressure on one side of the valve and personnel working on the other side of the valve. If the TSO valve 8

leaks, this presents problems for the personnel working downstream. In the past, NHD has had to delay 9

maintenance due to leaking TSO valves. Recently, NHD has repaired two TSO valves. Additional 10

valves may be candidates for repair, but some cannot be repaired due to the design and age and must 11

instead be replaced. 12

The high-pressure piping at Big Creek 3, Big Creek 4, and Big Creek 8 powerhouses is 13

original installation material, which ranges in age from 60 to 90 years old. Many of these piping 14

systems are at the end of their safe, reliable life. 15

2. Project Scope 16

For EHD, the projects will require removal of the existing TSO valves and replacement 17

with new ball valves. The projects will include engineering, purchasing, fabrication, installation, and 18

testing. (Ref 107-109) 19

The project scope Big Creek 3, 4, and 8 high Pressure Piping includes engineering, 20

design, purchase, installation and startup/test activities for the installation of a new primary water supply 21

system. The existing system will be repaired in order to become a backup to the new primary system. 22

(Ref. 111-113) 23

46


The benefit of these TSO valve projects will be to ensure reliable and safe operation for 2

SCE’s hydro facilities. Failure of one of these valves could cause flooding and damage to that facility. 3

The justifications for High Pressure Piping projects are both safety and reliability. The 4

present degraded piping poses a safety concern due to its potential failure, which could result in flooding 5

of the powerhouse. To date, leaks have been limited to the piping on the low-pressure portion of the 6

system, which is downstream of the pressure regulation equipment. However, if further piping 7

degradation occurs, a leak could occur on a large high pressure line, which flood the powerhouse before 8

the penstock flow may could be shut off. 9

The existing water systems do not meet current piping codes per industry standards, 10

because the system was installed prior to industry adoption of standards. A new piping system will be 11

designed to meet all current applicable code requirements. A failure of the high pressure piping system 12

will cause a powerhouse outage because there is no standby cooling system. A planned outage of 13

several weeks will be needed to replace the piping following engineering and procurement. In-service 14

failure of a TSO valve would increase the length of outage. 15

E. Prime Mover Replacements 16

The Mammoth Pool Fish Water Generator (MPFWG) has approximately 1 MW capacity and is 17

located adjacent to the downstream side of Mammoth Pool reservoir. Due to the increased instream 18

releases planned with the new FERC license (see Big Creek ALP Relicensing in Chapter II.B above), 19

the MPFWG can potentially be increased to a capacity of 3.6 MW. Engineering is currently underway 20

to determine the most cost efficient generator size to install. The present unit is certified as a Renewable 21

resource and it is expected that the new unit will be certified after installation. 22

This project was delayed from the last rate case due to the delay in the relicensing process. The 23

project requires FERC review and approval, which cannot be performed until the license has been issued 24

and engineering has been completed. The capital forecast for this project is $29.300 million for 2013-25

2017. Table IV-17 below shows the MPFWG project and the cost of its replacement. 26

47

Table IV-17 Prime Mover Replacements

(Nominal $)

REF WBS Element Prime Mover Replacements 2013 2014 2015 2016 2017 TOTAL114 CG0-00-PP-HN-000072 Mammoth Pool Fishwater Generator Replacement 950 1,500 9,000 14,600 3,250 29,300

(Nominal Values are in $1000's) Total 950 1,500 9,000 14,600 3,250 29,300

1. Background 1

The Mammoth Pool Reservoir was constructed circa 1960. The original installation 2

included a fixed cone (Howell-Bunger) valve and 1 MW “fishwater” turbine generator set (FWG), both 3

located in the dam bypass tunnel. Terms of the present FERC re-licensing require that a new release 4

schedule of water into the San Joaquin River between the reservoir and Mammoth Pool power house be 5

implemented. The new FERC license for Mammoth Pool will require an increase from 30 cfs to 150 cfs 6

for fish water flows. Additionally the new license requires periodic flows up to 850 cfs for recreation. 7

The new requirements, which greatly increase the required flow rates to the river, cannot be met with the 8

existing equipment located in the dam bypass tunnel. In order to meet the new requirements, the 9

equipment must be relocated outside of the tunnel. This is due to the increased size of the equipment 10

and for personnel safety to avoid entering a tunnel while high flows are exiting the tunnel. The new 11

infrastructure will require a significant amount of coordination and engineering. The remote location 12

and the winter weather conditions add to the difficulty of this project. 13

A reliable source of power is required for operation of the new release works. Based on a 14

reliability analysis of the Stevenson 12kV line serving reservoir area, local generation is the more 15

reliable choice. 16

2. Project Scope 17

The scope of work for this project includes engineering, design, purchase, installation, 18

and startup/test activities for the installation of a new turbine generator and power house outside of the 19

tunnel. Next steps include: (1) obtaining a license; (2) finalizing design engineering; (3) submitting for 20

and receiving FERC approval; (4) soliciting bids for equipment and purchase necessary equipment; (5) 21

soliciting construction bids, evaluating bids, and awarding a construction contract; (6) building 22

necessary civil/structural infrastructure; (7) installing new equipment; and (8) testing the new equipment 23

to ensure the new equipment meets all requirements. (Ref. 114) 24

48


The new fish water and recreation release requirements expected under the new FERC 2

license cannot be met with the existing equipment. Once the new license is awarded, SCE must comply 3

with the entire requirement. Local generation at Mammoth Pool is desirable to maintain stability on the 4

Stevenson 12kV line serving the reservoir area and for mandated release requirements. 5

F. Prime Movers – Miscellaneous Projects 6

The Prime Movers capital category includes turbines, generators, governors, turbine shutoff 7

valves, and high pressure piping systems, as discussed above. Miscellaneous projects in the Prime 8

Movers category include generator lead replacements, TSO valve controls, fire suppression system, and 9

TSO valves in Northern Hydro’s powerhouses. The capital forecast for these 12 projects is $6.400 10

million for 2013-2017. Table IV-18 is a list of the 12 Prime Mover Miscellaneous projects and the cost 11

for each. 12

Table IV-18 Prime Mover Miscellaneous

(Nominal $)

LINE REF WBS Element Prime Movers Miscellaneous Projects 2013 2014 2015 2016 2017 TOTAL1 116 CG0-00-PP-HE-000106 Kern River 1 Unit 2 - Replace Unit Governor 500 - - - - 500 2 117 CG0-00-PP-HE-000006 Rush Creek Unit 1 - Install Deflector - 900 - - - 900 3 118 CG0-00-PP-HE-000006 Bishop 6 - Replace Generator TSO Motors - 100 - - - 100 4 119 CG0-00-PP-HE-000006 Bishop 2 - Install Unit Needle Operators - - 250 - - 250 5 120 CG0-00-PP-HE-000006 Bishop 4 - Replace Generator TSO Motors - - 100 100 100 300 6 121 CG0-00-PP-HE-000006 Kern River 1 Unit 1 & Unit 3 Replace Governors - - - 800 - 800 7 122 CG0-00-PP-HE-000006 Lundy Install Unit Needle Operators - - - 250 - 250 8 123 CG0-00-PP-HE-000089 Poole - Replace TSO and Actuator 100 - - 50 250 400 9 124 CG0-00-PP-HE-000006 Borel - Install Generator on Spare Exciter Header - - - - 50 50 10 125 CG0-00-PP-HE-000006 Kern River 1 Unit 4 - Replace Unit Governor - - - - 400 400 11 126 CG0-00-PP-HE-000006 Lundy - Replace Generator TSO Motors - - - - 250 250 12 127 CG0-00-PP-HN-000025 Northern Hydro Miscellaneous Prime Movers 1,100 1,100 2,200 13 (Nominal Values are in $1000's) Total 600 1,000 350 2,300 2,150 6,400

1. Background 13

Hydro Prime Movers include a variety of ancillary equipment necessary for safe and 14

reliable operation of the powerhouses. Most of the equipment is in excess of 50 years old and has 15

surpassed their original expected life and in need of replacement. There is a value included for 16

undetermined projects that are known to occur and cannot be forecasted with certainty except for the 17

estimate of value. 18

49

2. Project Scope 1

The Prime Movers - Miscellaneous Projects category includes replacing turbines, 2

generators, governors, turbine shutoff valves, and high pressure piping systems, generator lead 3

replacements, TSO valve controls, and fire suppression systems. (Ref. 116-127) 4


The type of benefit varies from project to project, but in, general, they are to provide 6

reliable and safe operations for the Hydro Prime Mover equipment. 7

50

V. 1

DAMS AND WATERWAYS 2

PPD operates and maintains 33 dams, 43 stream diversions, and approximately 143 miles of 3

tunnels, conduits, flumes, flowlines, and pressurized penstocks. Maintaining this critical infrastructure 4

represents our largest category of Hydro capital investment. Many facilities are located in mountainous 5

terrain at elevations over 7,000 feet above sea level. These locations are remote and difficult places to 6

work. The nature of these locations increases capital costs. The work sites have limited access with 7

little room for mobile cranes and other equipment. These sites are also subject to cold weather, ice, and 8

deep snow in the winter months. Contractors must be familiar with this environment and be trained to 9

safely work in these areas. The need to pay for travel and lodging can increase our contractors' labor 10

costs. Many contractors opt for simpler work and simply will not bid on these projects. 11

Dams and Waterways projects include the rebuilding of reservoirs, flowlines, or flumes, 12

installation of flow measurement equipment, replacement of valves, and installation of debris removal 13

equipment or fish screens. The large projects in this category will sufficiently restore affected facilities 14

to ensure operation for several decades. The Dams and Waterways capital forecast for both Eastern and 15

Northern Hydro projects is $141.995 million for 2013-2017. The following Table V-19 shows the major 16

programs and projects for the Dams and Waterways category. 17

Table V-19 Dams and Waterways Major Programs & Projects

(Nominal $)

LINE REF DAMS & WATERWAYS 2013 2014 2015 2016 2017 TOTAL1 128-146, 252, 253 Gates & Valves 575 2,340 1,155 4,150 1,850 10,070 2 147-149 Structures Improvement 2,250 4,100 1,000 - - 7,350 3 150-160 Dam Surface Protection 3,275 4,074 11,450 18,850 8,600 46,249 4 161-173 Flowline Replacement 636 640 2,464 2,278 3,282 9,300 5 183-212 Major Dams & Waterway Projects 6,191 11,550 12,803 17,850 12,202 60,596 6 213-215 Dams & Waterways - Miscellaneous 250 2,070 2,555 2,000 1,555 8,430 7 (Nominal Values are in $1000's) Total 13,177 24,774 31,427 45,128 27,489 141,995

A. Gates and Valves Projects 18

The Hydro water conveyance systems utilize gates and valves to control the transfer of water 19

from one location to another. Some gates and valves are used to regulate the volume of flow and others 20

are used only in an “Open” or “Closed” mode. These gates and valves are essential for the reliable and 21

safe operation of the Hydro facilities. 22

51

The capital forecast for these 19 projects is $10.070 million for 2013-2017. Table V-20 below 1

provides a list of the 19 Gates and Valves projects and the cost for each. 2

Table V-20 Gates and Valves

(Nominal $)

LINE REF WBS Element Gates & Valves 2013 2014 2015 2016 2017 TOTAL1 128 CG0-00-PP-HE-000085 Sabrina - Replace Gate Operator 300 - - - - 300 2 129 CG0-00-PP-HE-000088 Lundy Lake - Replace Farmers Gate 25 200 - - - 225 3 131 CG0-00-PP-HE-000038 South Lake Intake - Install Pipe & Valve - 1,100 - - - 1,100 4 132 CG0-00-PP-HE-000038 Rush Creek - Replace TSO Actuator - 300 - - - 300 5 133 CG0-00-PP-HE-000038 Bishop - Intake 5 AVM - 250 - - - 250 6 134 CG0-00-PP-HE-000038 Bishop 2 - Replace Upper Penstock Valve - 175 - - - 175 7 135 CG0-00-PP-HE-000038 Abelour - Replace Headgate - 50 - - - 50 8 136 CG0-00-PP-HE-000038 Bishop 5 - Replace Upper Penstock Valve - - 175 - - 175 9 137 CG0-00-PP-HE-000038 Bishop South Fork - Replace Sand Trap Valve - - 150 - - 150

10 138 CG0-00-PP-HE-000038 Gem Lake - Replace Air Valves - - 80 - - 80 11 139 CG0-00-PP-HE-000038 Borel Install Penstock AVM's - - - 300 - 300 12 140 CG0-00-PP-HE-000038 Bishop 4 - Replace Upper Penstock Valve - - - - 175 175 13 141 CG0-00-PP-HE-000038 Bishop 3 - Replace Upper Penstock Valve - - - - 175 175 14 142 CG0-00-PP-HN-000069 Florence Lake Replace Min. Pool Weir Gate & - - - 0.1 - 0 15 143 CG0-00-PP-HN-000041 Huntington Lake Dam 1 Replace Upstream - - - 750 - 750 16 144 CG0-00-PP-HN-000041 Florence to Ward tunnel inlet gates & inlet - - 100 1,500 1,400 3,000 17 146 CG0-00-PP-HN-000041 Camp 62 Replace Valve Actuator - 165 - - - 165 18 252 CG0-00-PP-HN-000041 Florence lake Dam Drum Gate Replacement - 100 650 1,600 100 2,450 19 253 CG0-00-PP-HE-000084 Bishop Intake 3 AVM Installation 250 - - - - 250 20 (Nominal Values are in $1000's) Total 575 2,340 1,155 4,150 1,850 10,070

1. Background 3

Gates and valves have a very long life and many have been in operation for decades. 4

Gates and valves that have exceeded their useful lives are usually so old that no replacement parts are 5

available. Therefore, only minor servicing can be done to these units until they are replaced with new 6

equipment. Some of the valves requiring replacement are in critical locations such as the South Lake 7

Tunnel Gate, Florence Lake Drum Gates, and the Florence Lake-Ward Tunnel Inlet gates. Failure of 8

these gates could result in consequences that include: 9

Failure to comply with FERC required instream releases. 10

Failure to allow water into designated flowlines to powerhouses, resulting in energy 11

loss due to water spilling from reservoirs. 12

Failure to allow water to drain from reservoirs, interfering with maintenance. 13

Failure in an open position, possibly causing flooding of facilities. 14

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2. Projects Scope 1

The scope of the gate and valve projects includes engineering of the replacement 2

components (often the nearby piping must be modified to fit new style gates or valves), consideration of 3

outage timing, removal of existing equipment, and installation of the new equipment. 4

The South Lake Tunnel was constructed in 1908. The tunnel conveys water from the 5

deepest point of the lake under the dam and discharges into the South Fork of Bishop Creek below the 6

dam. In the mid 1950's, a concrete plug was installed in the tunnel upstream of the discharge point 7

along with a valve downstream of the plug and several hundred feet of 30” pipe. This improvement was 8

made because of concerns that the condition of the overlying rock on the lower section might not be 9

satisfactory to contain the pressure within the tunnel. The current project is being pursued because the 10

piping is deteriorating and access to the valve below the plug cannot be readily accessed in the event of 11

an emergency because the location is now classified as a confined space under current OSHA 12

regulations. Additional benefits include: (1) increasing the size of the valve and pipe which will allow 13

the reservoir to be drawn down more quickly in the event of an emergency; (2) the ability to operate the 14

valve below the plug remotely in the event of an emergency; (3) installation of a modern electric 15

generator and control system, which are currently located within the tunnel; and (4) moving the 16

generator and control system to a safer location outside of the tunnel. (Ref. 131) 17

The existing Florence Lake Ward Tunnel Inlet Gates require replacement. The inlet gates 18

are deteriorating and allow water to enter the Ward Tunnel, causing safety issue for workers in the 19

tunnel and allowing the water level in Florence Lake to drop below minimum pool, which is a 20

compliance issue. The work scope will include: (1) replacement of the existing drum gates including all 21

piping, seals, and actuators; (2) evaluation of all mechanical and metal structures when water is down to 22

determine need for replacement; (3) installation of an automated system in order to allow the gates to be 23

operated remotely from the dispatch building, allowing more precision and safely; (4) installation of an 24

AVM flow meter; and (5) replacement of all associated piping. (Ref. 144) 25

The existing Florence Lake Drum Gates are original to the structure and have exceeded 26

their useful life. The work scope will include: (1) replacement of the existing drum gates, including all 27

piping, seals, and actuators; (2) evaluation of all mechanical and metal structures when water is down to 28

determine need for replacement; (3) installation of an automated system in order to allow the gates to be 29

operated remotely from the dispatch building at Big Creek, allowing more precise flow control and 30

53

safety; (4) installation of an acoustic velocity flow meter (AVM); and 5) replacement of all associated 1

piping. (Ref. 252) 2


Upgrading the existing 60 year old worn piping, valves, and controls at the South Lake 4

Intake will allow SCE to continue to operate this high risk dam and reservoir by meeting current 5

regulatory and safety standards. The addition of the larger discharge pipe will increase public safety by 6

allowing the lake to be drained more rapidly in the event of a thunderstorm event. This concern has 7

been noted in the PFMA studies related to the SCE Dam Safety Program. 8

The benefit of replacement of these gates and valves vary among the projects. Virtually 9

all have a benefit of increased reliability and safety. Most of the larger projects are required for 10

changing flows due to impending FERC license requirements. The present reporting method does not 11

provide adequate flow measurement while flumes and AVMs provide improved reporting of instream 12

release flow data to maintain compliance with the FERC License. 13

B. Structures Improvements 14

The capital forecast for the 3 Structure Improvement projects is $7.350 million for 2013-2015. 15

Table V-21 below provides a list of the 3 Structure Improvement projects and the cost for each. 16

Table V-21 Structures Improvement

(Nominal $)

LINE REF WBS Element Structures Improvement 2013 2014 2015 2016 2017 TOTAL1 147 CG0-00-PP-HE-000094 Rebuild Birch McGee Intake 250 - - - - 250 2 148 CG0-00-PP-HE-000078 Kern River Flowline - Rebuild Sandbox 850 2,000 500 - - 3,350 3 149 CG0-00-PP-HE-000079 Kern River 3 - Dam & Intake Refurbishment 1,150 2,100 500 - - 3,750 4 (Nominal Values are in $1000's) Total 2,250 4,100 1,000 - - 7,350

1. Background 17

The Kern River 3 Sandbox is a large concrete settling basin, which allows sediment from 18

upstream to settle from the water. This provides cleaner water to be diverted into the flowline that 19

supplies Kern River 3 powerhouse. An engineering inspection report in 2006 recommended that major 20

rehabilitation work be done to the sandbox due to serious erosion. These replacements, when 21

completed, will increase safety for employees and reliability. 22

The Kern River 3 Dam and Intake structure is subject to erosion that has worsened the 23

last few years due to high sediment loading from the McNally fire in 2002. The intake house has shifted 24

and shows a large crack in the concrete block structure that has been patched and sealed numerous 25

54

times. The flume, as well as many portions of the intake structure inside the grid area, show signs of 1

wear that require patching. 2

2. Projects Scope 3

New FERC license requirements stipulate that the Kern River 3 Sandbox be flushed once 4

a week, which also adds to the erosion of the sandbox floors and support structures. An engineering 5

inspection and report conducted in 2006 by the PPD engineering group recommends that major work be 6

performed on the structure in the near future to maintain continued reliability. 7

The Kern River 3 Sandbox work scope includes: (1) developing an engineering package 8

to identify work scope, cost and schedule to rebuild the sandbox structure; (2) removing deteriorated 9

concrete liner, inject cracks to seal them, and installing a new reinforced concrete liner; (3) inspecting 10

support beams and refurbished as required; and (4) inspecting and refurbishing exterior walls. (Ref. 148) 11

The Kern River 3 Dam and Intake structure work scope includes: (1) the development of 12

an engineering package to identify work scope, cost and schedule to refurbish the dam and intake 13

structure; (2) removal of the deteriorated concrete liner and injecting cracks to seal them; (3) installation 14

of a new reinforced concrete liner; (4) replacement of the intake house and foundation; (5) replacement 15

of the existing security fence; and (6) inspection and repair of the flume walls. (Ref. 149) 16


The dam, intake structure and sandbox at Kern River 3 are vital components in the 18

powerhouse flowline. The concrete structure deteriorates over time due to water and weather erosion. 19

Exposed rebar must not be allowed to rust or it will lead to further failure of the concrete and possible 20

failure if not maintained properly. A failure would result in lost generation at the plant and depending 21

on the extent of damage, an unforeseen outage due to structural failure could last 6-12 months. 22

Additionally, a failure could result in large amounts of captured solids entering the Kern River, causing 23

environmental damage. 24

C. Dam Surface Protection and Seismic Refurbishment 25

Dam Surface Protection and Seismic Refurbishment projects are required to improve the surface 26

protection of dams located within both Eastern and Northern Hydro facilities. The capital forecast for 27

these 11 projects is $46.249 million for 2013-2017. (Ref 150-160) Table V-22 is a list of the 11 Dam 28

Surface Protection projects and the cost for each. 29

55

Table V-22 Dam Surface Protection

(Nominal $)

LINE REF WBS Element Dam Surface Protection 2013 2014 2015 2016 2017 TOTAL1 150 CG0-00-PP-HE-000064 Saddlebag Dam - Wood Spillway Modification 1,600 - - - - 1,600 2 151 CG0-00-PP-HE-000116 Waugh Dam - Seismic Upgrade/Pressure Grout 350 350 350 6,000 6,000 13,050 3 152 CG0-00-PP-HE-000082 Gem Lake Dam - Reface Down Stream Side 300 300 4,300 12,000 2,000 18,900 4 153 CG0-00-PP-HE-000083 Tioga Dam - Install Geomembrane 50 1,100 - - - 1,150 5 154 CG0-00-PP-HE-000092 Bishop Intake 4 - Resurface Spillway 25 250 - - - 275 6 155 CG0-00-PP-HE-000027 Bishop Intake 3 - Resurface Spillway - 25 250 - - 275 7 156 CG0-00-PP-HE-000115 Agnew Dam - Resurface Dam/Seismic Upgrade 650 4,800 - - 5,450 8 157 CG0-00-PP-HN-000059 Florence Dam Geomembrane Liner - 450 1,250 250 1,950 9 158 CG0-00-PP-HN-000066 Huntington Lake Dam Geomembrane Liner 200 200

10 159 CG0-00-PP-HN-000042 Northern Hydro Dam Automation & Leakage 650 500 600 600 2,350 11 160 CG0-00-PP-HN-000089 Vermilion Dam Monitoring & Drain Improvement 750 299 1,049 12 (Nominal Values are in $1000's) Total 3,275 4,074 11,450 18,850 8,600 46,249

1. Background 1

The Hydro concrete dams experience harsh conditions during the winter months that 2

degrade the dam surface over time and cause a loss of surface material from the dam. In addition when 3

water migrates through the concrete dam structure, the bonding agents in the concrete can be leached 4

from the concrete, weakening the structure. In order to protect dams from surface or interior 5

degradation, the surface can be coated with concrete gunite or a geomembrane liner. 6

2. Projects Scope 7

The projects in this category use either concrete gunite or a geomembrane liner coatings 8

for refurbishment of dam surfaces. Some of the Hydro multiple-arch dams require seismic 9

strengthening due to the location of nearby geological faults. This work will be engineered to meet the 10

latest seismic requirements and ensure the structure life for several decades. The projects include 11

performing engineering work to add geomembrane liners for Tioga, Agnew Saddlebag, Florence Lake, 12

and Huntington dams. Gunite coating will be used for the gravity section of Gem dam. 13

The project at Saddlebag Dam includes working to place an engineered geomembrane 14

liner system over the entire upstream face of the dam to eliminate seepage through the existing redwood 15

facing, as well as replacing redwood-faced spillway with a more robust material that is erosion resistant. 16

The reservoir will be drained and the base of the dam cleared of debris in order to expose the foundation. 17

The installation will proceed in the most efficient way, typically applying the geomembrane in vertical 18

strips across the dam face. Anchoring will be into the wood facing or support stringers, using chemical 19

anchors suitable for wood fastening. Drains will be installed at low points to allow any water trapped 20

56

behind the liner to drain as reservoir levels drop. Redwood lining on the spillway will be removed and a 1

suitable material will be placed to render a more robust spillway design. (Ref. 150) 2

Waugh Dam has exhibited a history of severe wear to the concrete components of the 3

dam due to the harsh environment of its location. Leakage is increasing despite the application of the 4

geomembrane liner. Design seismic ground motions have increased significantly since the dam was 5

built in 1925. Increased seismic design loads have led to stability and structural strength concerns. It is 6

believed that major rehabilitation of the deteriorated concrete, placement of a concrete buttress along the 7

downstream side, and additional post-tensioned anchors along the crest of the dam will alleviate the 8

seismic concerns and allow the reservoir to be safely operated at full capacity. (Ref. 151) 9

The Gem Lake Dam project will repair concrete that has been damaged by freeze/thaw 10

conditions. The seismic refurbishment plan will include removing deteriorated concrete, placing 11

reinforcing steel as necessary, and developing an appropriate concrete mix that is compatible with the 12

local dam environment. A lateral load carrying system will be designed to resist seismic forces parallel 13

to the dam crest. In 2014, the repair plan will be implemented, with contractor work proceeding through 14

the summer months. Construction activities will continue through 2017. (Ref. 152) 15

The project at Tioga Dam includes work to place an engineered geomembrane liner 16

system over the entire upstream face to eliminate seepage through the existing redwood facing. The 17

reservoir will be drained and the base of the dam cleared of debris in order to expose the foundation. 18

The installation will proceed in the most efficient way, typically applying the geomembrane in vertical 19

strips across the dam face. Anchoring will be into the wood facing or support stringers, using chemical 20

anchors suitable for wood fastening. Drains will be installed at low points to allow any water trapped 21

behind the liner to drain as reservoir levels drop. (Ref. 153) 22

The project at Agnew Dam includes work to place an engineered geomembrane liner 23

system over the entire upstream face to eliminate seepage through the existing concrete structure. The 24

reservoir will be drained and the base of the dam cleared of debris in order to expose the foundation. 25

The installation will proceed in the most efficient way, typically applying the geomembrane in 26

horizontal strips across the dam face. Drains will be installed at low points to allow any water trapped 27

behind the liner to drain as reservoir levels drop. The seismic refurbishment plan will include removing 28

deteriorated concrete, placing reinforcing steel as necessary, and developing an appropriate concrete mix 29

that is compatible with the local dam environment. A lateral load carrying system will be designed to 30

resist seismic forces parallel to the dam crest. Pressure grouting will be performed at appropriate 31

57

locations in the rock adjacent to the upstream face of the dam. The existing steel trash rack will be 1

removed and discarded. Concrete repairs will be conducted to provide proper support for the new trash 2

rack. A composite material trash rack will be installed. (Ref. 156) 3

Florence Lake Dam was constructed in 1926, and, due to its age, it has experienced 4

freeze/thaw spalling. In order to prevent further freeze/thaw from occurring and extend the life of the 5

dam line, SCE’s Engineering and Technical Services Dam Safety group has recommended that we coat 6

the upstream face of the dam with a geo-membrane coating that has been successfully used in Eastern 7

Hydro and at Shaver Lake. The lining system has the potential to significantly decrease dam 8

maintenance and improve the dam stability. The work includes: (1) obtaining regulatory and 9

environmental approvals to perform the work; (2) directing a purchase order to Carpi International for 10

the materials and installation of a Geo-membrane for Huntington Lake Dam; (3) purchasing all the 11

materials required to line the upstream face of the dam; and (4) installing the liner. (Ref. 157) 12

The Vermillion Dam monitoring and drain improvement project scope consists of: (1) 13

installation of a concrete wire gauging station at confluence of 28+25 and Mono creek; (2) drilling holes 14

and installing Piezometers at toe of the dam to monitor leakage; and (3) digging exploratory trenches 15

across the auxiliary spillway to compare construction material found onsite with the original auxiliary 16

spillway design. If the construction material that is found onsite does not match the original design then 17

a remediation plan for future construction will be developed. (Ref. 160) 18


Refacing the dams will comply with FERC dam safety requirements and ensure 20

continued safe and reliable operation for the duration of the FERC license. The justification for some of 21

these projects is necessary to comply with FERC and DSOD requirements. 22

The Vermillion Dam project is required to determine if the existing auxiliary spillway 23

was required for overflow conditions. If the spillway was not constructed according to the original 24

design there may be a possibility that the spillway will not perform as expected and could jeopardize the 25

safe operation of the dam. 26

D. Flowline Replacement 27

As mentioned above, SCE Hydro maintains 143 miles of flowlines. These flowline replacement 28

projects include various types of designs and materials: steel flumes on wood structures, concrete pipe, 29

steel pipe, concrete canals, and concrete v-ditches. These projects include replacement of over five 30

58

miles of flowline during the record period. The capital forecast for these 13 projects is $9.300 million 1

for 2013-2017. Table V-23 is a list of the 13 flowline replacement projects and the cost for each. 2

Table V-23 Flowline Replacement

(Nominal $)

LINE REF WBS Element Flowline Replacement 2013 2014 2015 2016 2017 TOTAL1 161 CG0-00-PP-HE-000096 Santa Ana River 1 - Flume Recoating/Retar 50 - 950 - - 1,000 2 162 CG0-00-PP-HE-000111 Kaweah 2 - Gunite Canals 250 - - - - 250 3 163 CG0-00-PP-HE-000099 Alder Creek - Replace Pipe 200 - - - - 200 4 164 CG0-00-PP-HE-000098 Lytle Creek Flowline - Siphon 4-5-6 Replacement 20 500 500 - - 1,020 5 165 CG0-00-PP-HE-000113 Tule Flowline - Rebuild 500' of Flume 116 - - - - 116 6 166 CG0-00-PP-HE-000051 Lytle Creek - Replace Flowline - - 50 200 200 450 7 167 CG0-00-PP-HE-000014 Tule Flowline Replacement - 120 124 128 132 504 8 168 CG0-00-PP-HE-000014 Ontario 1 - Siphon 1-2-3-4 Replacement - 20 500 500 - 1,020 9 169 CG0-00-PP-HE-000014 Kaweah 2 - Replace Steel Flume Sheets - - 300 300 300 900

10 170 CG0-00-PP-HE-000014 Fontana Penstock - Replacement/Install Coating - - 20 500 500 1,020 11 171 CG0-00-PP-HE-000014 Lytle Creek Flowline - Siphon 1-2-3 Replacement - - 20 500 500 1,020 12 172 CG0-00-PP-HE-000014 Kaweah 3 - Replace Upper (Horizontal) Penstock - - - - 1,650 1,650 13 173 CG0-00-PP-HE-000066 Bishop - Replace South Fork Flowline - - - 150 - 150 14 (Nominal Values are in $1000's) Total 636 640 2,464 2,278 3,282 9,300

1. Background 3

Flowlines utilizing flumes require frequent replacement due to the exposure to weather 4

conditions. Concrete canals must be recoated with gunite on a periodic basis to maintain integrity of the 5

structure. Some installations with steel or concrete pipe are over 80 years old and are exhibiting leakage 6

and must be replaced. Flumes and flowlines are visually inspected regularly to identify and monitor 7

conditions. When a concern is identified a more in-depth inspection is performed. If the condition is 8

such that replacement is required then the project is initiated. 9


The project scope is similar for all 13 projects. Generally, SCE will: (1) create 11

engineering and drawings for the project; (2) obtain permitting as appropriate for the location; (3) 12

evaluate the impact of the flowline outage with downstream water users; (4) purchase the materials for 13

the flowline; and (5) install the flowline and associated equipment. (Ref. 161-173) 14


Most flowlines pass through areas that would impact the public by flooding if a failure 16

occurred. Failure of either a flume or flowline can have any of several consequences including potential 17

endangerment of the public, negative impact on the environment in the form of severe soil erosion 18

and/or slides, and interruption of some portion of the flow through the tunnel. Project benefits include 19

59

maintaining reliability for operation of the affected Hydro facilities and maintaining safety for operation 1

personnel and the public. 2

E. Major Dams and Waterways Projects 3

These projects consist of eight varying projects. The capital forecast for these eight projects is 4

$60.596 million for 2013-2017. Table V-24 provides a list of the eight Major Dams and Waterways 5

projects and the cost for each. 6

Table V-24 Major Dams and Waterways

(Nominal $)

REF WBS Element Major Dams & Waterway Projects 2013 2014 2015 2016 2017 TOTAL174 CG0-00-PP-HE-000037 Kaweah 1 - Flowline Rehabilitation 1,800 1,500 1,500 1,500 1,500 7,800 175 CG0-00-PP-HE-000109 Kern River 3 - Rebuild Tunnel 1,611 5,400 500 - - 7,511 176 CG0-00-PP-HE-000025 Borel - Rebuild Canal & Tunnels 550 550 600 600 1,300 3,600 178 CG0-00-PP-HE-000015 Kern River 1 - Rebuild Tunnel Phase 5 - - - - 50 50 179 CG0-00-PP-HE-000050 Bishop 6 - Replace Flowline/Install AVM - - - 150 5,000 5,150 180 CG0-00-PP-HN-000070 Mammoth Pool HB Valve Replacement 1,000 1,500 7,903 14,600 3,250 28,253 181 CG0-00-PP-HN-000067 Northern Hydro Dams Seismic Improvements 500 2,100 1,800 1,000 1,102 6,502 182 CG0-00-PP-HN-000068 Northern Hydro Dam Structure Improvement 730 500 500 1,730


1. Kaweah 1 - Flowline Rehabilitation 7

a) Background 8

The flume that conveys water for generation to Kaweah 1 Powerhouse is in need 9

of replacement. The wooden flume structure is deteriorating due to age and repeated exposure to 10

weather cycles. The flume is at the point where repairs can no longer be made. A failure of the flume 11

could potentially result in damage to public and private lands and property due to erosion and washout 12

of the supporting soil. 13


This project will be implemented to repair deterioration that has developed in 15

Kaweah Flowline. The project scope involves the removing and replacement of all existing lumber, 16

flume sheets, and associated materials as well as replacement of existing wooden footings with 17

prefabbed concrete footings. The capital forecast for this project is $7.800 million for 2013-2017. (Ref. 18

174) 19


An incremental approach to repair the Kaweah 1 Flume has been initiated during 21

prior years. The work contemplated herein is a continuation of that incremental approach. The main 22

justification for the project is public safety, reliability, and safer O&M of the existing water structures. 23

60

2. Kern River 3 – Rebuild Tunnel 1

a) Background 2

The Kern 3 Tunnel System is constructed of mainly unreinforced concrete with 3

only limited section of closed conduit and adit access locations having steel reinforcement. A number of 4

the closed conduit areas are supported above ground and failure at these locations would release water 5

which would erode the hillsides and possibly flood the public road. The tunnel system is approximately 6

12 miles long with some locations where construction access audits are at least six miles away. 7

b) Projects Scope 8

This project will be implemented to repair deterioration and erosion damage that 9

has developed in the Kern 3 tunnel system since its construction. The rehabilitation work involved in 10

this project will consist of repair and/or replacement of structural concrete sections of floors, walls, and 11

cap (roof). Areas of floor damage will require removal of large sections of damaged concrete and 12

replacement with new sections. Some of these areas may require special ground water protections for 13

water pressure and inflow. Wall areas that support cap sections will need to be repaired to return them 14

to sufficient structural integrity for useful and uninterrupted flow through the tunnel. Repairs to closed 15

conduit sections will consist of repair and/or replacement of sections of the concrete conduit to correct 16

damage due to corrosion that has led to leakage and lack of structural support for cap sections. The 17

capital forecast for this project is $7.511 million for 2013-2015. (Ref. 175) 18


The failure at any of the damage locations can have any of several consequences, 20

including potential endangerment of the public, negative impact on the environment in form of severe 21

soil erosion and/or slides, and interruption of some portion of the flow through the tunnel. A full 22

engineering assessment of the degree of damage and risk is part of this project and the specific 23

remediation work will be more defined after that assessment is completed. 24

3. Borel - Rebuild Canal and Tunnels 25

a) Background 26

The Borel Flowline, commonly referred to as the Borel Canal, is a series of 27

concrete lined canals, tunnels, and flumes that delivers water from the outlet gate of the auxiliary dam at 28

Lake Isabella to the Borel powerhouse. The water flow is controlled using gates at the auxiliary dam that 29

are operated by the United States Army Corps of Engineers (ACOE). The canal has many areas in need 30

of repair that have been eroded by many years of service. 31

61

The ACOE has found that the auxiliary dam at Lake Isabella has a seismic fault 1

line running under it that has been recently classified as an active fault. Because of this re-classification, 2

the ACOE has determined that the dam needs to be retrofitted to bring the dam up to current public 3

safety standards. This study also impacts our Borel Canal. The fault line also runs through one of the 4

tunnels along the Borel Flowline. The Federal Energy Regulatory Commission (FERC), the ACOE, and 5

SCE have been working together to determine the type and magnitude of seismic activity that could 6

occur and what consequences might result. With these determinations we have concluded that the Borel 7

canal requires seismic improvements in order to withstand a seismic event and also to protect the public 8

in the event the canal is damaged during the event. The work by ACOE to the auxiliary dam also 9

impacts the timing of the Borel project, since an outage should be taken when their dam is out of 10

service. 11


This project will be implemented to rebuild the Borel canal and tunnels. The 13

project will consists of: (1) installing newly engineered gates, power and communication systems for 14

remote monitoring; and (2) installation of new power poles and transformers to provide location for 15

local warning devices that will be installed along the water diversion channel. Installation of new 16

monitoring equipment will enable quick recognition of problems. Repairs to the canal lining and flumes 17

will be engineered as well as new vehicle entry ramps, new fencing in certain areas, and road 18

restructuring. The capital forecast for this project is $3.600 million for 2013-2017. (Ref. 176) 19


The major justifications for this project are continued reliability and addressing 21

the public safety issues of a seismic event causing a tunnel collapse or liner cracking, causing water to 22

overtop the canal. FERC has recommended improvements that will counter the consequences of such an 23

event. Improvements to security fencing will provide much greater public safety around the populated 24

areas near the canal. We also have recognized some deterioration in the canal liner and flume coatings 25

that may, over time, cause excessive leakage and possible major damage to the canal with environmental 26

consequences. 27

4. Bishop 6 – Replace Flowline/Install AVM 28

a) Background 29

This project involves the replacement of approximately 4,000 feet of existing 30

flowline for Bishop Creek Plant 6 powerhouse. 31

62

b) Projects Scope 1

The existing pipe will be excavated and removed. A new section of pipe 2

approximately 4,000 feet long will be transported to the site in segments and welded in place. Various 3

environmental, archeological, and historic studies are underway and/or have been completed. The 4



The existing pipe has deteriorated to an extent where a long-term solution is 7

required. 8

5. Mammoth Pool Reservoir HB Valve Replacement 9

a) Background 10

Mammoth Pool Reservoir was constructed circa 1960. The original installation 11

included a fixed cone (Howell-Bunger) valve and 1 MW “fishwater” turbine generator set, both located 12

inside the dam bypass tunnel. Terms of the impending FERC license6 require that a new release 13

schedule of water into the San Joaquin River between the reservoir and Mammoth Pool power house be 14

implemented. The expected FERC license for Mammoth Pool will require an increase from 30 cfs to 15

150 cfs for instream release flows. Additionally, the new license requires periodic flows up to 850 cfs 16

for recreation boating flows. The new requirements, which greatly increase the required flow rates to 17

the river, cannot be met with the existing release equipment inside the dam bypass tunnel. For employee 18

safety, the new release system employs a new penstock inside the tunnel and relocation and resizing of 19

the existing Howell-Bunger valve and fishwater generator. The new infrastructure needed to meet these 20

new requirements will be significant. This will be a very large project and require a significant amount 21

of coordination and engineering. The remote location and the winter weather conditions add to the 22

difficulty of this project. 23


The scope of work includes engineering, design, purchase, installation and 25

startup/test activities for the installation of a new water release system, including new fixed cone valves 26

and a new penstock inside the tunnel. The new water release point has been moved outside of the 27

bypass tunnel for operator safety. In addition, upgrades to the existing access road are required in order 28

to provide safe access to the tunnel mouth for delivery of material and equipment, and construction. The 29


6 Refer to II.B for further information regarding the Big Creek Relicensing effort.

63


The expected FERC license for Mammoth Pool will require an increase from 30 2

cfs to 150 cfs for instream release flows. Additionally, the new license requires periodic flows up to 850 3

cfs for recreation boating flows. The new requirements cannot be met with the existing equipment. 4

Once the new license is awarded, we must comply with the requirements within several years. The 5

project includes relocation of the equipment to outside of the tunnel. This provides a safety benefit 6

because the high volume of release occurring in the tunnel does not provide a safe path for the operator 7

to access the valves, which are currently deeper in the tunnel than the release point. 8

6. Northern Hydro Dams Structure and Seismic Retrofit Projects 9

a) Background 10

The Part 12 Independent Consultants' Inspection Reports for several Northern 11

Hydro Division Dams, including Big Creek Dams 5, 6, and 7, Huntington Lake Dams 1 and 2, Florence 12

Lake Dam, and Mammoth Lake Dam, dated 2006, 2007, 2011, and 2012, have recommended that 13

stability analyses be performed based on the updated seismic and hydrological load. The 14

recommendations by the Independent Consultants have been reviewed by the FERC, who requested that 15

the analyses be performed. Stability analyses are planned for completion during 2013. If the new 16

analyses indicate a Dam stability improvement is necessary, a retrofit project will be required with 17

completion by 2015. 18


The scope of work may include additional anchorage post tension tendons, and/or 20

buttresses downstream of the dam. Final decision on the retrofitting scheme will be made after the 21

analyses are completed in 2013. The capital forecast for these projects is $8.232 million for 2013-2017. 22

(Ref.181 and 182) 23


The improvement program will provide sufficient stability of the dams against 25

strong earthquakes and the Probable Maximum Flood (PMF) as required by the FERC and California 26

Department of Water Resources, Division of Safety of Dam (DSOD). As a result, public safety 27

downstream of the dam will be improved. 28

F. Dams and Waterways – Miscellaneous 29

Dams and Waterways projects include the rebuilding of reservoirs, flowlines, or flumes, 30

installation of flow measurement equipment, replacement of valves, and installation of debris removal 31

64

equipment or fish screens. Previous sections provide information for specific capital projects pertaining 1

to Dams and Waterways. This section includes miscellaneous projects such as walkways, 2

communication equipment, penstock protection, fishwater generator, and others. The capital cost for 3

these 29 projects is $8.430 million for 2013-2017. Table V-25 below is a list of the specific Dams and 4

Waterways projects and the cost for each. 5

Table V-25 Dams and Waterways Miscellaneous Projects

(Nominal $)

LINE REF WBS Element Dams & Waterways - Miscellaneous 2013 2014 2015 2016 2017 TOTAL1 183 CG0-00-PP-HE-000007 Lundy Clay Liner 50 - - - - 50 2 185 CG0-00-PP-HE-000102 Borel Forebay Install Crane 200 - - - - 200 3 186 CG0-00-PP-HE-000007 Santa Ana River 3 - Penstock Upgrade Protection - 300 - - - 300 4 187 CG0-00-PP-HE-000007 Mill Creek 3 - Flowline Replacement - 50 - - 450 500 5 188 CG0-00-PP-HE-000007 Kaweah 3 - Resurface Middle Fork Intake - 400 - - - 400 6 189 CG0-00-PP-HE-000007 Green Creek Diversion Replacement - 250 250 250 - 750 7 190 CG0-00-PP-HE-000007 Bishop 2 Intake 3 - Install AVM - 250 - - - 250 8 191 CG0-00-PP-HE-000007 Kaweah 3 - Replace Middle Fork Diversion Dam - 150 - - - 150 9 192 CG0-00-PP-HE-000007 Lundy Powerhouse Bypass/Install - 50 350 - - 400

10 193 CG0-00-PP-HE-000007 Bishop 5 - Replace Station Cranes - 120 - - - 120 11 194 CG0-00-PP-HE-000007 Kaweah 1 - Forebay Replace - - 950 - - 950 12 195 CG0-00-PP-HE-000007 Kaweah 3 - Resurface Marble Fork Intake - - 200 - - 200 13 196 CG0-00-PP-HE-000007 Kaweah 3 - Gunite Tailrace - - 125 - - 125 14 197 CG0-00-PP-HE-000007 Rush Creek - Replace Station Crane - - 100 - - 100 15 198 CG0-00-PP-HE-000007 Bishop 2 - Replace Station Cranes - - 80 - - 80 16 199 CG0-00-PP-HE-000007 Mill Creek 1 - Spincoat Penstock - - - 20 400 420 17 200 CG0-00-PP-HE-000007 Ontario 1 - Spincoat Penstock - - - 400 - 400 18 201 CG0-00-PP-HE-000007 Kaweah 2 - Install Forebay Grid Rake and - - - 100 - 100 19 202 CG0-00-PP-HE-000007 Kaweah 2 - Replace Forebay Spill Chute - - - 95 - 95 20 203 CG0-00-PP-HE-000007 Kaweah 2 - Gunite Forebay - - - 225 - 225 21 204 CG0-00-PP-HE-000007 Kern River 3 - Replace Forebay Gate Operators - - - 150 - 150 22 205 CG0-00-PP-HE-000007 Borel - Rebuild Tailrace - - - - 200 200 23 206 CG0-00-PP-HE-000007 Kern River 1 Forebay - Install Steel Walkway - - - 600 - 600 24 207 CG0-00-PP-HE-000007 Bishop 6 - Replace Station Cranes - - - 80 - 80 25 208 CG0-00-PP-HE-000007 Bishop 3 - Replace Station Cranes - - - 80 - 80 26 209 CG0-00-PP-HE-000007 Kaweah 1 - Replace Main Gate Valve at Intake - - - - 25 25 27 210 CG0-00-PP-HE-000007 Ontario 2 - Spincoat Penstock - - - - 400 400 28 211 CG0-00-PP-HE-000007 Bishop 4 - Replace Station Cranes - - - - 80 80 29 212 CG0-00-PP-HN-000027 Northern Hydro Misc. Dams & Waterways 500 500 1,000 30 (Nominal Values are in $1000's) Total 250 2,070 2,555 2,000 1,555 8,430

1. Background 6

Dams and Waterways are an essential part of the Hydro system, providing transportation 7

and control of the fuel used for hydroelectric power generation. This category covers a wide variety of 8

projects that are essential for continued reliable and safe operation of the Hydro facilities that comply 9

with applicable regulations. 10


The Dams and Waterways miscellaneous projects include specific projects in both 12

Eastern and Northern Hydro Divisions. 13

65

The dams and waterways in the NHD are all in excess of 50 years old and have been well 1

maintained over the period. However, improvements due to new regulations and operating experience 2

will be required in the future which are currently undefined. Although it is not possible to predict the 3

necessary improvements, it is prudent to provide funding for this work. (Ref. 212) 4


These necessary projects must be accomplished to maintain a reliable and safe hydro 6

system. Some of the work in this section is regulatory requirements for FERC or DSOD. 7

66

VI. 1

STRUCTURES AND GROUNDS 2

This category generally involves needed work related to structures including the powerhouses, 3

roofs, cranes, heating ventilation and air conditioning, and to infrastructure including roads, bridges, 4

paving, fencing and gates, fire and water systems, and wastewater projects. The major projects in this 5

category are road improvements, communications equipment, wastewater treatment, and structure 6

roofing. The Structures and Grounds capital forecast for Hydro projects is $41.912 Million for 2013-7

2017. The following Table VI-26 shows the major programs and projects for the Structures and 8

Grounds category. 9

Table VI-26 Structures and Grounds Major Programs & Projects

(Nominal $)

LINE REF STRUCTURES & GROUNDS 2013 2014 2015 2016 2017 TOTAL1 213-215 Building Improvements 925 50 175 - - 1,150 2 216-220 Road Improvement & Paving 2,650 750 - - - 3,400 3 221-226 Major Structures & Grounds Projects 20,097 5,000 100 - - 23,197 4 230-254 Miscellaneous Structures & Grounds 783 860 3,030 3,800 3,692 14,165 5 (Nominal Values are in $1000's) Total 24,455 6,660 3,305 3,800 3,692 41,912

A. Building Improvement Projects 10

Many of the Hydro powerhouse and ancillary structures require major refurbishment. This 11

category of capital projects is to return structures to an acceptable, presentable condition that will meet 12

current health, safety, and building codes. The capital cost for these three projects is $1.150 million for 13

2013-2015. Table VI-27 below provides a list of the three specific Building Improvement projects and 14

the cost for each. 15

Table VI-27 Hydro Building Improvement Projects

(Nominal $)

LINE REF WBS Element Building Improvements 2013 2014 2015 2016 2017 TOTAL1 213 CG0-00-PP-HE-000114 Kaweah 1 - Maintenance/Civil Shop 100 - - - - 100 2 214 CG0-00-PP-HE-000009 Bishop 4 - Construction Office - 50 175 - - 225 3 215 CG0-00-PP-HN-000044 Northern Hydro Powerhouse Structure Improvements 825 - - - - 825 4 (Nominal Values are in $1000's) Total 925 50 175 - - 1,150

67

1. Background 1

Capital budgeting in the previous 10 years was primarily targeted at power production 2

equipment rather than the powerhouse structures or investing in company housing. It is now necessary 3

to invest capital to refurbish powerhouse structures, refurbish and build additional company housing, 4

and refurbish a number of administration/operation buildings. 5

2. Project Scope 6

The Building Improvement projects vary in scope according to their location. Kaweah, 7

Bishop and Big Creek (Northern Hydro) powerhouse structure improvements are essential for 8

maintaining an acceptable level of quality of the facilities. The aged structures are overdue for a 9

rehabilitation investment, which will greatly improve their appearance. (Ref. 213-215) 10


The benefit of these projects is to refurbish the structures at a lower cost than if the 12

projects are delayed, causing further degradation. Roof replacement projects provide for replacement of 13

roofs that must be repaired to ensure generating equipment is not subjected to unexpected water leaks. 14

B. Road Improvement and Repaving 15

PPD maintains approximately 120 miles of private roads, spread throughout our hydroelectric 16

system, which are needed to access our remote sites. We are anticipating approval of the Big Creek 17

ALP FERC license conditions, which will require us to assume maintenance responsibility for an 18

additional 70 miles of mountain roads.1 Capital projects include major repairs to existing roads and 19

other road improvements to address traffic safety and ensure safe transportation of large equipment to 20

and from job sites. Most roads are located in areas of severe weather. They experience significant snow 21

removal equipment damage, high rain and snow melt erosion along the shoulder or across the lanes, and 22

undergo several "freeze and thaw" cycles each year. Also, these roads are generally located in steep 23

terrain and in areas where only a limited amount of road base preparatory work is practical. Hence, 24

subsurface settlement and movement also stresses the roads, creating fractures and potholes which 25

quickly grow when subjected to the elements. The capital cost for these three projects is $3.400 million 26

for 2013-2014. Table VI-28 below provides a list of the five specific Road Improvement projects and 27


68

Table VI-28 Hydro Road Improvement and Paving

(Nominal $)

LINE REF WBS Element Road Improvement & Paving 2013 2014 2015 2016 2017 TOTAL1 216 CG0-00-PP-HE-000062 Kern River 3 - Flowline Road Work 2,500 750 - - - 3,250 2 217 CG0-00-PP-HE-000110 Kern River3 - Replace Adit 19-20 Bridge with Culvert 50 - - - - 50 3 220 CG0-00-PP-HN-000080 Northern Hydro Road Overlays & Replacement 100 - - - - 100 4 (Nominal Values are in $1000's) Total 2,650 750 - - - 3,400

1. Background 1

SCE provides road maintenance as needed. However, complete restoration of the asphalt 2

surface is still necessary every 10 to 15 years. As with all Hydro construction projects, road repair costs 3

are relatively high. Almost all roads are located in relatively remote areas. Road repair projects incur 4

added material transportation costs and premiums paid for labor. 5

The Kern River Flowline Roads are in major need of repair. The roads have become 6

narrower and steeper due to continued erosion. Many of the roads are in an unsafe condition and those 7

who use the roads need to take extra precautions when driving them. We are unable to take large 8

equipment or vehicles into some areas if needed for maintenance activities due to the condition of the 9

roads. 10


Project scope is similar in most road improvement projects and consists of surveying of 12

the road to determine that drainage is properly maintained and that severely damaged areas are repaired 13

prior to paving, surface preparation, repairing road base, and installation of the top asphalt layer. 14

Many areas of the Kern River Flowlines need to be widened with dirt removal and/or by 15

building retaining structures in areas with steep embankments. Many culverts are in need of either 16

repair or replacement. There are areas of the flowline where new roads may need to be cut for access to 17

adits. Blasting will be necessary in some spots depending on the terrain and geological makeup of the 18

area. (Ref. 216) 19


The benefit of the road improvement projects is to insure traffic safety and allow for 21

prompt response of our employees and safety personnel to the sites during plant emergencies. 22

Tunnel repairs to the Kern River system will need to be performed in the future and 23

repair of the roads is necessary accommodate the vehicle and equipment traffic necessary for the tunnel 24

69

work. Many of the roads are in an unsafe condition and safety is a concern for personnel traveling the 1

roads. 2

C. Major Structures and Grounds Projects 3

These projects consist of five varying projects. The capital forecast for these five projects is 4

$23.197 million for 2013-2015. Table VI-29 is a list of the Major Structures and Grounds projects and 5


Table VI-29 Major Structures and Grounds

(Nominal $) REF WBS Element Major Structures & Grounds Projects 2013 2014 2015 2016 2017 TOTAL221 CG0-00-PP-HE-000093 Bishop 4 - Replace Fuel System 575 - - - - 575 222 CG0-00-PP-HE-000090 Bishop 4 - Water System/Install Domestic Well 2,025 - - - - 2,025 223 CG0-00-PP-HE-000046 Rush Creek - Rebuild Tram Track and Replace Tram Car 4,000 5,000 100 - - 9,100 224 CG0-00-PP-HN-000086 Big Creek 1 Camp Cottage Renovations 3,497 - - - - 3,497 225 - - - - - - 226 CG0-00-PP-HN-000087 Big Creek 1 Construct Admininistration/Dispatch Office 8,000 - - - - 8,000

(Nominal Values are in $1000's) Total 18,097 5,000 100 - - 23,197

1. Bishop 4 – Water System/Install Domestic Well 7

a) Background 8

The existing Bishop Plant 4 sewer and water systems have extensive leaks and no 9

longer meet current plumbing codes. The water piping is primarily composed of galvanized pipe, which 10

is badly corroded. In addition, a new power system upgrade for the Administration and Shop facilities 11

will require removal of asphalt throughout the camp and presents a perfect opportunity to upgrade the 12

sewer and water system. 13


This project includes replacing existing sewer and domestic water system. The 15

scope will include all new sewer piping from each source within the Bishop Plant 4 Camp, Plant, Shops 16

and Administration facilities to the point of connection with the septic system. New domestic water 17

piping and storage tank modifications will meet current water system standards and the new well will 18

provide redundancy. Additionally, a new well and control system will be installed to supplement the 19

existing single well. The capital forecast for this project is $2.025 million for 2013. (Ref. 222) 20


The current system does not comply with Inyo County requirements. As part of 22

the project, the storage tank and piping to the tank will be upgraded to meet current codes per requests 23

70

from the local county Environmental Health Department. Replacement will ensure compliance and 1

provide reliable service for many years. 2

2. Rush Creek Rebuild Tram Track & Replace Tram Car 3

a) Background 4

The current tram system at Rush Creek is a narrow gauge track system about one 5

mile long with a single cable attached to the tram car and powered by a winch at the top on the hill. The 6

track system has had numerous attempts at repair, but it still suffers from misalignment and material 7

deterioration. The cable drive system needs replacement of cable guides the entire length of the track as 8

well as other upgrades to meet today’s standards. This project will replace the entire project including 9

the tram car with current, modern equipment. 10


The project includes the engineering design necessary to revamp the system and 12

to select and procure the proper replacement equipment. The old system will be demolished including 13

all rails and cable guide structures. The cable house may also need to be demolished depending on the 14

design of the replacement equipment selected in the engineering process. A new track and tie system 15

along the old pathway will be installed along with new control systems. The tram car will be mounted 16

on the new structures and tested thoroughly prior to be put into normal operations. The capital forecast 17

for this project is $9.100 million for 2013-2015. (Ref. 223) 18


The project provides greatly improved efficiency of operation and improves the 20

safety of operating personnel using the tram. The tram is an essential mode of transportation from the 21

Rush Creek Powerhouse to Agnew Lake for personnel and materials. Other modes of transportation are 22

a hiking trail, helicopter, or mules. 23

3. Big Creek 1 Camp Cottage Renovations 24

a) Background 25

In the 2009 GRC, funds were approved to update existing housing in the Big 26

Creek work camp that was old and not compliant with today’s code requirements. We are now in the 27

last phase of this project, which is scheduled for completion in 2013. The Big Creek 1 Camp Cottage 28

Renovations update existing housing in the Big Creek work camp that was old and not compliant with 29

today’s code requirements. 30

71

b) Projects Scope 1

The project will complete the last phase of the 2012 GRC (D.12-11-051, pages 59 2

and 824) approved refurbishment of existing company housing. The capital cost for this project is 3

$3.497 million for 2013. (Ref. 224) 4


The benefit of the project is to provide housing that meets current health, safety, 6

and code requirements for the ongoing safety of employees and their families and to attract new hires to 7

the Big Creek locations. 8

4. Big Creek 1 Construct Administration and Dispatch Office 9

a) Background 10

In the near future NHD will have new operating licenses from the FERC. The 11

new licenses will require significant changes in the way we operate the project. The changes will 12

increase regulatory compliance requirements that will necessitate closer coordination between the 13

hydrographers, Hydro Station Operators (HSO1) and the Regulatory Compliance Department. A new 14

dispatch center located in the Big Creek area will increase our ability of maintaining compliance within 15

our new license requirements. It will also provide additional security, meeting NERC CIP7 16

requirements, for the dispatch center and powerhouse operational equipment. 17

The existing dispatch center, at Big Creek 3, is located within the flood plain 18

boundary of the San Joaquin River. If a 100 year storm were to occur, or one of the upstream dams 19

were to fail, the dispatch center could potentially be flooded and render the project unable to function 20

and operate as needed. Relocating the Dispatch Building to Big Creek and out of the flood plain will 21

increase operations reliability and provide a safer working location for the HSO1’s. Additionally, 22

management will have immediate access to information if an emergency were to occur, increasing the 23

effectiveness of incident command. 24

The new Administration office will bring together four key groups that 25

communicate frequently and are currently separated geographically: Engineering & Project 26

Management, Compliance, Water Operations, and Upper Management. 27


This project includes the work necessary to complete construction of the new 29

dispatch/administration building that was started in 2012. Work left to complete includes completion of 30

7 See NERC Critical Infrastructure Protection (CIP) Version 5 Policy section in SCE-09 Chapter VIII.

72

(1) interior finishes; (2) equipment and ovation system installation; (3) final site work; (4) furniture 1

installation; (5) landscaping, and (6) final punch list items. The capital cost for this project is $8.000 2

million for 2013. (Ref. 226) 3


The new dispatch center will provide a central secure location for the operation of 5

the Northern Hydro system. The building will house all of the key operational departments. The new 6

dispatch center will provide the main operational center, the old dispatch center will provide a redundant 7

operational center in case of emergency. 8

D. Structures and Grounds – Miscellaneous Projects 9

Structures and Grounds miscellaneous projects include a variety of work such as power pole 10

replacement, HVAC systems, fire water lines, roofing work, and others. The capital cost for these 15 11

projects is $14.165 for 2013-2017. Table VI-30 below is a list of the specific miscellaneous projects and 12


Table VI-30 Structures and Grounds – Miscellaneous

(Nominal $)

REF WBS Element Miscellaneous Structures & Grounds 2013 2014 2015 2016 2017 TOTAL230 CG0-00-PP-HE-000086 Bishop 2 - Replace Powerhouse Roof 100 - - - - 100 231 CG0-00-PP-HE-000040 Poole - Replace Powerhouse Roof - 100 150 - - 250 232 CG0-00-PP-HE-000040 Lee Vining - Replace Roof - - 80 - - 80 233 CG0-00-PP-HE-000040 Bishop 3 - Replace Powerhouse Roof - - - 100 - 100 234 CG0-00-PP-HE-000040 Rush Creek - Garage Asbestos Removal - - - 200 - 200 235 CG0-00-PP-HE-000040 Poole Plant - Garage Asbestos Removal - - - 200 - 200 236 CG0-00-PP-HE-000040 Bishop 2 - Garage Asbestos Removal - - - - 200 200 237 CG0-00-PP-HE-000040 Bishop 4 - Garage Asbestos Removal - - - - 242 242 238 CG0-00-PP-HE-000040 Bishop 5 - Replace Powerhouse Roof - - - - 100 100 239 CG0-00-PP-HE-000040 Bishop 5 - Replace Sewer System - - - - 50 50 240 CG0-00-PP-HN-000084 Big Creek 3 Replace Domestic Water Service 50 - - - - 50 241 CG0-00-PP-HN-000092 Big Creek 4 Replace Domestic Water Service 50 - 600 600 500 1,750 242 CG0-00-PP-HN-000090 Florence Lake Replace Camp Domestic Water Line 63 - - - - 63 244 CG0-00-PP-HN-000031 Northern Hydro Misc. Structures & Grounds Projects 2,520 500 1,700 2,200 2,000 8,920 254 CG0-00-PP-HN-000064 Mammoth Pool Powerhouse Covered Storage 260 500 500 600 1,860

(Nominal Values are in $1000's) Total 2,783 860 3,030 3,800 3,692 14,165

1. Background 14

Structures and Grounds projects support the infrastructure that is essential to maintaining 15

the workplace setting for the other capital categories. 16

Big Creek 4’s domestic raw water system is old and in need of replacement. The water is 17

taken off of the penstock for Powerhouse 4 or from the tailrace and is pumped into a large storage tank 18

through a line in excess of 500 feet in length. The water is gravity fed to pumps that feed the water 19

treatment plant at Big Creek 4. This water also feeds the plant fire protection system. Many 20

73

modifications have been made to the system over the years and bypasses around abandoned sections 1

make the system difficult to control. The system controls are over 30 years old and need to be brought 2

up to today’s standards. The system needs to be redesigned and replaced in order to provide a reliably 3

operating system for future years of plant operation. 4

The construction of a new covered storage area adjacent to the machine shop at 5

Mammoth Pool Powerhouse will provide an area that will protect material that is currently stored 6

outside in the weather with no forklift access. 7

2. Projects Scope 8

The project scope varies according to the project. This category includes funds for 9

undetermined projects for both Eastern and Northern Hydro. 10

The domestic raw water system replacement at Big Creek 4 requires removing the 11

existing piping and equipment prior to installing new piping from the penstocks and tailraces to the new 12

storage tanks that will be installed as a part of the projects. New pumps will be installed along with 13

upgraded electrical supply and control systems. The water treatment equipment at Big Creek 4 will be 14

inspected and overhauled as necessary. (Ref. 241) 15

Not all capital projects can be identified within the five year capital window. The 16

Structures and Grounds area is one in which such occurrences have been experienced recently that 17

require completion in three or less years. This capital item recognizes such occurrences and establishes 18

funding for those Structures and Grounds projects to cover these necessary but unexpected expenditures. 19

The scope of the miscellaneous structures and grounds allowance item will be determined as the 20

inevitable unexpected failures occur and specific fixes for each case are identified. (Ref. 244) 21

The scope of the Mammoth Pool Powerhouse covered storage building project is the 22

construction of a new building from an engineering design that has already been completed. (Ref. 254) 23


The benefit of these projects is to maintain the structures and grounds in good working 25

condition. The type of benefit varies from project to project. Equipment sometimes fails unexpectedly 26

or regulations and environmental permits change faster than anticipated which require capital 27

expenditures to maintain compliance. 28

The domestic and raw water systems at Big Creek 4 are old and in need of replacement as 29

the lines are prone to leaks. Upgrading the existing systems will bring them up to current design and 30

environmental standards. 31

74

Construction of a covered storage area at the Mammoth Pool Powerhouse will allow 1

material to be stored in a controlled environment and mitigate an existing safety hazard due to lack of 2

forklift access that requires material to be moved by hand. 3

75

VII. 1

FURNITURE, TOOLS AND EQUIPMENT 2

Routine Blanket Work Orders provide for replacement of the following: 3

Furniture and office equipment. 4

Portable tools and equipment. 5

Laboratory, test, and technical equipment. 6

Miscellaneous Work Equipment and Spare Parts. 7

Table VII-31 summarizes our capital forecast for Furniture, Tools and Equipment which totals 8

$1.446 million. Our forecast reflects decreased spending compared to prior years. 9

Table VII-31 Furniture, Tools and Equipment

(Nominal $)

REF WBS Element Furniture, Tools & Equipment 2013 2014 2015 2016 2017 TOTAL245 CG0-00-PP-HE-000001 Furniture & Office Equipment 70 - - - - 70 246 CG0-00-PP-HE-000003 Portable Tools & Equipment 150 - - - - 150 247 CG0-00-PP-HE-000011 Lab, Testing & Technical Equipment 238 - - - - 238 248 CG0-00-PP-HN-000017 Misc. Work Equipment and Spare Parts 540 - - - - 540 255 CGO-00-PP-DB-000033 PPD Home Office Water Chemistry Lab 10 - - - - 10 256 CGO-00-PP-DB-000034 PPD Home Office Training Center 40 - - - - 40 257 CGO-00-PP-DB-000036 PPD Home Office E&TS 248 - - - - 248 258 CGO-00-PP-DB-000000 PPD Home Office - Office Furniture 150 - - - - 150

(Nominal Values are in $1000's) Total 1,446 - - - - 1,446

A. Furniture and Office Equipment 10

Our Office Furniture and Office Equipment capital estimate includes furniture and office 11

equipment for the PPD staff office, E&TS, the Training Center, and the Water Chemistry Lab. (Ref. 12

245) 13

B. Portable Tools and Equipment 14

Our Portable Tools and Equipment capital estimate includes small testing and monitoring 15

equipment used by E&TS, the Training Center, and the Water Chemistry Lab. The largest portion of the 16

increase will be for equipment for training new hires. (Ref. 246) 17

C. Laboratory, Testing and Technical Equipment 18

Our Laboratory, Testing, and Technical Equipment capital estimate includes testing equipment 19

for both the Training Center facilities and the Water Chemistry Lab. Necessary equipment includes 20

training simulation systems, and analytical tools that measure electrical parameters, thermography, 21

vibration, and water chemistry, as well as other applications. (Ref. 247) 22

76

D. Miscellaneous Work Equipment and Spare Parts 1

The Miscellaneous Equipment and Spare Parts capital estimate includes larger fixed equipment 2

such as lathes, drill presses, cranes, and other miscellaneous equipment. The five-year capital estimate 3

reflects the need for new equipment for the mid-canyon machine shop. (Ref. 248) 4

E. Power Production Division (PDD) Home Office 5

The SCE Power Production Division (PPD) office is located in San Dimas, California. The staff 6

at this location supports the generation facilities including Hydro, Mountainview, and Peakers. 7

Associated with the PPD staff is the Engineering & Technical Services (E&TS) staff, the Training 8

Center staff, the Water Chemistry Lab, and other support functions such as regulatory compliance. 9

These expenditures fund tooling and equipment needed to perform these support functions. (Ref. 255-10

258) 11

77

VIII. 1

DECOMMISSIONING - SAN GORGONIO 2

A. San Gorgonio Hydro Project 3

Mill Creek and the San Gorgonio projects are in the process of being decommissioned. Due to 4

contractual obligations and proposed US Forest Service requirements, it is anticipated that SCE will be 5

required to do a significant amount of construction work on the San Gorgonio facilities before turning 6

the project over to the local water agencies. To complete this work, the anticipated cost for these two 7

projects will be $7.076 million dollars in 2013-2017. (Ref. 249-250) Table VIII-32 summarizes our 8

capital forecast for these two projects. 9

Table VIII-32 Decommissioning

(Nominal $)

LINE REF WBS Element Decommissioning 2013 2014 2015 2016 2017 TOTAL1 249 CG0-00-PP-HE-000008 Mill Creek 2 - Decommissioning 200 - - - - 200 2 250 CG0-00-PP-HE-000017 San Gorgonio Canyon - Decommissioning 376 500 2,000 2,000 2,000 6,876 3 (Nominal Values are in $1000's) Total 576 500 2,000 2,000 2,000 7,076

1. Background 10

San Gorgonio 1 (SG1) and San Gorgonio 2 (SG2) were constructed in 1923 with 11

respective capacities of 1.5 MW and 0.94 MW. In order to enhance the flow in the San Gorgonio River, 12

additional flow was diverted from the Whitewater River, which would normally flow to the Morongo 13

Valley. This diverted water in the San Gorgonio River flows to Banning, not the Morongo Valley, 14

which caused the Morongo Indians to lose water that would otherwise go to their reservation. This was 15

contested, but over-ruled during the last FERC relicensing in 1983. It is believed that a new FERC 16

relicensing, due in April, 2003, would have resulted in a 50 percent loss of water for generation. 17

SG1 is located upstream from SG2, so flow from SG1 will feed SG2 from a flowline. 18

This flowline travels through very steep terrain, some of which is unstable. This area frequently 19

required rebuilding. Due to the low flow available for generation, SG1 and SG2 were designed with 20

water storage tanks, which would fill up with water diverted for power generation. When the tanks were 21

full, the turbines would operate until the tanks were empty. The operating capacity from 1975 to 1998 22

averaged 15 percent, compared to approximately 47 percent for SCE Hydro total. In fall of 1998, a level 23

controller on the SG1 tank malfunctioned and overflowed the tank. The water running down the side 24

washed out the base of the tank, causing it to collapse. 25

78

SCE decided not to pursue the FERC relicensing of the SG1 and SG2 facilities in 2001 1

when the FERC Notice of Intent was due for the 2003 expiration of the San Gorgonio FERC license. 2

This was due to the high costs of maintaining and relicensing a very low capacity production facility, 3

which needed major work and would likely lose a significant portion of its generation in the process of 4

relicensing. 5

2. Projects Scope 6

SCE is bound by contract to deliver water through its facilities to the downstream water 7

user, Banning Heights Mutual. Therefore SCE must convey the facilities in a condition that will pass 8

water before Banning Heights Mutual will agree to assume ownership. The following work must be 9

done prior to conveyance to satisfy them and the US Forest Service: 10

Reline canal sections from the East and South Forks of the San Gorgonio to Raywood 11

Flats 12

Refurbish the flowline from Burnt Canyon to below SG1 13

Remove flowline trestles in the area of Raywood Flats 14

Remove all generation equipment, SG2 water tank, and some sections of flow line as 15

directed by the US Forest Service (Ref. 250) 16


The benefit of the San Gorgonio Decommissioning project is to eliminate future costs for 18

flowline upkeep, which was agreed to in historical water contracts. Future generation benefits from the 19

two very small powerhouses did not exceed the costs of returning to service plus FERC relicensing 20

costs.21

Appendix A Witness Qualifications

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF TIMOTHY CONDIT 3

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

A. My name is Timothy Condit, and my business address is 300 N. Lone Hill in San Dimas, CA 5

91773. 6

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

A. I am a Project Manager II within the Power Production Division. My responsibilities include 8

preparation of information and documentation to support regulatory filings, data requests, and 9

business analyses. 10

Q. Briefly describe your educational and professional background. 11

A. I received my Bachelor of Science degree in Civil Engineering from Arizona State University in 12

1998. I joined SCEs Northern Hydroelectric Division in 2010. In my initial position as a Project 13

Manager I, I managed construction projects for SCE’s Northern Hydroelectric Division. I 14

transferred from the Northern Hydro Division to the Power Production staff of Operations 15

Support & Performance Improvement in September of 2012, assuming my current position as a 16

Project Manager II. 17

Q. What is the purpose of your testimony in this proceeding? 18

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-02, Vol. 07, Pt. 2: 19

Generation – Hydro Capital, as identified in the Table of Contents thereto. 20

Q. Was this material prepared by you or under your supervision? 21

A. Yes, it was. 22

Q. Insofar as this material is factual in nature, do you believe it to be correct? 23

A. Yes, I do. 24

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 25

judgment? 26

A. Yes, it does. 27

Q. Does this conclude your qualifications and prepared testimony? 28

A. Yes, it does. 29

Appendix B SCE Hydro Capital Projects

For 2013 – 2017 (Nominal Values are in $1000’s)

B-1

REF WBS Element FERC Relicensing 2013 2014 2015 2016 2017 TOTAL1 CG0-00-PP-HN-000046 Big Creek 1 Relicensing 668 3,169 1,064 740 1,905 7,545 2 CG0-00-PP-HN-000047 Big Creek 2 Relicensing 668 3,169 1,064 740 1,905 7,545 3 CG0-00-PP-HN-000049 Big Creek 8 Relicensing 2,295 1,033 1,587 625 1,042 6,583 4 CG0-00-PP-HN-000050 Big Creek 3 Relicensing 195 298 294 500 825 2,111 5 CG0-00-PP-HN-000051 Big Creek 2A Relicensing 2,295 1,033 1,587 625 1,042 6,583 6 CG0-00-PP-HN-000052 Mammoth Pool Relicensing 200 1,152 132 25 390 1,899 7 CG0-00-PP-HN-000053 Eastwood Relicensing 2,295 1,033 1,587 625 1,042 6,583 8 CG0-00-PP-HN-000054 Vermillion Relicensing 423 1,397 824 253 2,630 5,527 9 CG0-00-PP-HN-000055 Big Creek 4 Relicensing 933 842 215 - - 1,990

10 CG0-00-PP-HN-000056 Portal Relicensing 223 2,497 566 205 735 4,226 (Nominal Values are in $1000's) Total 10,194 15,622 8,920 4,338 11,517 50,590

REF WBS Element Infrastructure Replacements 2013 2014 2015 2016 2017 TOTAL11 CG0-00-PP-HE-000074 Mt. Tom Substation 360 - - - - 360 12 CG0-00-PP-HE-000091 White Mountain Substation 1,000 - - - - 1,000 13 CG0-00-PP-HE-000057 Lee Vining Substation 400 2,250 20,000 - - 22,650 14 CG0-00-PP-HE-000058 Minaret Substation - 250 3,000 250 - 3,500 15 CG0-00-PP-HE-000055 Casa Diablo Substation - 1,000 1,600 2,000 - 4,600 16 CG0-00-PP-HE-000070 Control Station - 1,000 - - - 1,000 17 CG0-00-PP-HE-000070 Inyo Substation - - 150 - - 150 18 CG0-00-PP-HE-000070 Skiland Substation - - 150 - - 150 19 CG0-00-PP-HE-000070 Magmagen Substation - - 100 1,000 100 1,200 20 CG0-00-PP-HE-000070 Deep Springs Substation - - - 15 800 815 21 CG0-00-PP-HE-000070 Bridgeport Substation - - - 50 1,000 1,050 22 CG0-00-PP-HE-000070 Zack Substation - - - 500 - 500 23 CG0-00-PP-HE-000070 Sherwin Substation - - - 150 1,000 1,150 24 CG0-00-PP-HN-000038 Northern Hydro Replace 12KV Substations - - - 3,000 3,300 6,300 25 CG0-00-PP-HN-000010 Big Creek 3 Replace 12 KV Substation 5,300 - - - - 5,300 26 CG0-00-PP-HN-000038 Timberwine 12KV Substation - 1,500 1,000 - - 2,500


REF WBS Element Region Automation Projects 2013 2014 2015 2016 2017 TOTAL27 CG0-00-PP-HE-000112 Kaweah - Automation Upgrade 5,700 - - - - 5,700 28 CG0-00-PP-HE-000104 Kern River - Automation Upgrade 2,200 2,000 - - - 4,200 29 CG0-00-PP-HE-000097 East End - Automation Upgrade 500 2,473 2,500 2,500 - 7,973 30 CG0-00-PP-HN-000081 Northern Hydro Automation Upgrades 300 300 300 300 300 1,500

(Nominal Values are in $1000's) Total 8,700 4,773 2,800 2,800 300 19,373

REF WBS Element Transformer Replacements 2013 2014 2015 2016 2017 TOTAL33 CG0-00-PP-HE-000023 Bishop 2 - Replace #3 Transformer Bank - 200 1,000 - - 1,200 34 CG0-00-PP-HE-000023 Bishop 5 - Replace #1 Transformer Bank - 950 50 - - 1,000 35 CG0-00-PP-HE-000023 Kern River 3 - Replace Local Service Banks - - - 500 - 500 36 CG0-00-PP-HE-000023 Borel - Replace 3 Phase Station Light & Power Bank - - - - 40 40 37 CG0-00-PP-HN-000037 Northern Hydro Transformer Replacements - 515 2,000 2,000 2,300 6,815 38 CG0-00-PP-HN-000058 Portal Main Bank Transformer 1,500 1,500


REF WBS Element Branch Circuit, Control & Relay Projects 2013 2014 2015 2016 2017 TOTAL40 CG0-00-PP-HE-000067 Poole - Replace Unit Breaker/ Station Light & Power 4,200 150 - - - 4,350 41 CG0-00-PP-HE-000072 Bishop 4 - AC Relay Protection/Excitation/Unit Breakers 1,258 150 - - - 1,408 42 CG0-00-PP-HE-000048 Rush Creek - Replace Relay Protection/AC Panels 67 - - - - 67 43 CG0-00-PP-HE-000024 Bishop 2 - Station Electrical Upgrade - - 250 3,000 - 3,250 44 CG0-00-PP-HE-000024 Bishop 3 - Unit Breaker/Relay Protection - - 250 100 2,000 2,350 45 CG0-00-PP-HE-000024 Kern River 3 - Replace Protective Relay Panels - 750 - - - 750 46 CG0-00-PP-HE-000024 Borel - Replace Control & Relay Panels - - - - 800 800 47 CG0-00-PP-HN-000057 Northern Hydro Backcountry Instrumentation 100 150 150 150 150 700

(Nominal Values are in $1000's) Total 5,625 1,200 650 3,250 2,950 13,675

ELECTRICAL EQUIPMENT

FERC RELICENSING

B-2

REF WBS Element Circuit Protection Equipment 2013 2014 2015 2016 2017 TOTAL49 CG0-00-PP-HE-000075 Ontario 1 Replace Circuit Breakers 400 - - - - 400 50 CG0-00-PP-HE-000022 Tule - Replace 66kv Circuit Breakers - 150 - - - 150 51 CG0-00-PP-HE-000022 Kaweah 3 - Replace 66kv Circuit Breakers - - 150 - - 150 52 CG0-00-PP-HE-000019 Kern River 3 - Replace 2.4kV Circuit Breakers - - - 500 - 500 53 CG0-00-PP-HE-000022 Kern River 3 - Replace 66kV Circuit Breakers - - - 2,065 - 2,065

(Nominal Values are in $1000's) Total 400 150 150 2,565 - 3,265

REF WBS Element Major Electrical Projects 2013 2014 2015 2016 2017 TOTAL54 CG0-00-PP-HE-000081 Bishop - Communication Fiber 400 500 2,500 - - 3,400 55 CG0-00-PP-HE-000020 Agnew - Replace 4KV Transformers and Transmission Line 1,000 2,000 250 - - 3,250 56 CG0-00-PP-HN-000036 Huntington Lake Dam 1 Replace Power & Controls 100 6,000 6,000 12,100


REF WBS Element Electrical Equipment - Miscellaneous 2013 2014 2015 2016 2017 TOTAL59 CG0-00-PP-HE-000005 Santa Ana River 1 - Water Controllers - 50 - - - 50 60 CG0-00-PP-HE-000005 Fontana - Replace/Upgrade Unit Breakers - - 200 - - 200 61 CG0-00-PP-HE-000005 Santa Ana River 1 - Replace Switchyard Breakers - - 30 - 950 980 62 CG0-00-PP-HE-000005 Sierra - Water Controllers - - 50 - - 50 63 CG0-00-PP-HE-000005 Ontario - Water Controllers - - 50 - - 50 64 CG0-00-PP-HE-000005 Santa Ana River 3 - Replace Switchyard Breakers - - - 30 - 30 65 CG0-00-PP-HE-000005 Borel Replace 2.4kV Busswork - - - - 100 100 66 CG0-00-PP-HN-000023 Big Creek 4 Low Voltage Switchgear - 50 250 - - 300 67 CG0-00-PP-HN-000023 Big Creek 4 ISO Bus Replacement Unit 1 & 2 - 50 - 250 - 300 68 CG0-00-PP-HN-000023 Big Creek 3 Circuit Breaker Replacement - 50 250 - - 300 69 CG0-00-PP-HN-000024 Eastwood PowerStation Pony Motor - 75 250 0 - 325 70 CG0-00-PP-HN-000023 Northern Hydro Miscellaneous Electrical 50 1,000 1,000 1,500 1,700 5,250


REF WBS Element Turbine Wicket Gates & Waterwheels 2013 2014 2015 2016 2017 TOTAL74 CG0-00-PP-HE-000105 Kern River 1 Unit 2 - Turbine Refurbishment 2,100 - - - - 2,100 75 CG0-00-PP-HE-000087 Bishop 3 Unit 2 - Turbine Refurbishment 500 - - - - 500 76 CG0-00-PP-HE-000100 Mill Creek 3 Unit 5 - Turbine Replacement 300 - - - - 300 77 CG0-00-PP-HE-000101 Mill Creek 3 Unit 3 - Turbine Replacement 30 400 - - - 430 78 CG0-00-PP-HE-000095 Santa Ana River 1 Turbine Refurbishments 50 100 900 900 - 1,950 80 CG0-00-PP-HE-000042 Mill Creek 3 Unit 4 - Turbine Replacement - 30 400 - - 430 81 CG0-00-PP-HE-000042 Bishop 5 Unit 1 - Turbine Refurbishment - 400 - - - 400 82 CG0-00-PP-HE-000042 Kern River 1 Unit 1 - Turbine Refurbishment - 1,500 - - - 1,500 83 CG0-00-PP-HE-000042 Bishop 2 Unit 1 - Turbine Refurbishment - - 400 - - 400 84 CG0-00-PP-HE-000042 Bishop 3 Unit 1 - Turbine Refurbishment - - 400 - - 400 85 CG0-00-PP-HE-000042 Borel Unit 2 - Replace Wicket Gates & Runner Seals - - - - 50 50 86 CG0-00-PP-HE-000042 Kern River 1 Unit 3 - Turbine Refurbishment - - 1,500 - - 1,500 87 CG0-00-PP-HE-000042 Bishop 4 Unit 2 - Turbine Refurbishment - - - 400 - 400 88 CG0-00-PP-HE-000042 Kern River 1 Unit 4 - Turbine Refurbishment - - - 1,500 - 1,500 89 CG0-00-PP-HE-000042 Bishop 4 Unit 1 - Turbine Refurbishment - - - - 400 400 90 CG0-00-PP-HE-000042 Bishop 4 Unit 5 - Turbine Refurbishment - - - - 400 400 91 CG0-00-PP-HN-000040 Northern Hydro Wicket Gates & Runners - - 150 200 3,650 4,000


REF WBS Element Generator Coils & Rewinds 2013 2014 2015 2016 2017 TOTAL92 CG0-00-PP-HE-000041 Bishop 5 Unit 1 - Rewind Generator / Rotor - 450 - - - 450 93 CG0-00-PP-HE-000041 Bishop 2 Unit 1 - Rewind Stator / Rotor - - 450 - - 450 94 CG0-00-PP-HE-000041 Borel Unit 2 - Stator Rewind & Replace Leads - - - - 100 100 95 CG0-00-PP-HE-000041 Bishop 2 Unit 3 - Rewind Generator / Rotor - - - 450 - 450 96 CG0-00-PP-HE-000041 Bishop 2 Unit 2 - Rewind Stator / Rotor - - - - 450 450 97 CG0-00-PP-HE-000041 Lundy Unit 1 - Rewind Stator / Rotor - - - - 450 450 98 CG0-00-PP-HN-000063 Mammoth Pool Unit 1 Rewind & Field Poles 2,000 - - - - 2,000 99 CG0-00-PP-HN-000060 Big Creek 3 Unit 3 Rewind & Field Pole 15 - - - - 15

100 CG0-00-PP-HN-000026 Northern Hydro Generator Rewinds 2,000 2,050 2,000 2,000 8,050 (Nominal Values are in $1000's) Total 2,015 2,450 2,500 2,450 3,000 12,415

PRIME MOVERS

ELECTRICAL EQUIPMENT (con't)

B-3

REF WBS Element Generator Excitation 2013 2014 2015 2016 2017 TOTAL101 CG0-00-PP-HE-000103 Borel - Install Solid State Exciters Units 1 & 2 300 - - - - 300 102 CG0-00-PP-HE-000103 Borel - Install Solid State Exciter Unit 3 - - - - 350 350 103 CG0-00-PP-HE-000071 Kern River 3 - Install Solid State Exciters - - 50 - - 50 104 CG0-00-PP-HE-000071 Kaweah 2 - Replace Excitation - - - - 125 125 105 CG0-00-PP-HN-000024 Big Creek 1 Unit 1 - Solid State Excitation 150 - - - - 150 106 CG0-00-PP-HN-000024 Big Creek 1 Unit 2 - Solid State Excitation 150 - - - - 150

(Nominal Values are in $1000's) Total 600 - 50 - 475 1,125

REF WBS Element Turbine Valves & High Pressure Piping 2013 2014 2015 2016 2017 TOTAL107 CG0-00-PP-HE-000108 Kern River 3 - Replace TSO Bypass Valves 155 - - - - 155 108 CG0-00-PP-HE-000031 Lytle Creek Units 1&2 Replace TSO Valve - - - 20 450 470 109 CG0-00-PP-HE-000031 Santa Ana River 1 Replace TSO Valves - - - 20 650 670 111 CG0-00-PP-HN-000079 Big Creek 4 High Pressure Piping 150 150 150 - - 450 112 CG0-00-PP-HN-000074 Big Creek 3 High Pressure Piping - - 150 150 150 450 113 CG0-00-PP-HN-000075 Big Creek 8 High Pressure Piping - - 150 150 600 900

(Nominal Values are in $1000's) Total 305 150 450 340 1,850 3,095

REF WBS Element Prime Mover Replacements 2013 2014 2015 2016 2017 TOTAL114 CG0-00-PP-HN-000072 Mammoth Pool Fishwater Generator Replacement 950 1,500 9,000 14,600 3,250 29,300


REF WBS Element Prime Movers Miscellaneous Projects 2013 2014 2015 2016 2017 TOTAL116 CG0-00-PP-HE-000106 Kern River 1 Unit 2 - Replace Unit Governor 500 - - - - 500 117 CG0-00-PP-HE-000006 Rush Creek Unit 1 - Install Deflector - 900 - - - 900 118 CG0-00-PP-HE-000006 Bishop 6 - Replace Generator TSO Motors - 100 - - - 100 119 CG0-00-PP-HE-000006 Bishop 2 - Install Unit Needle Operators - - 250 - - 250 120 CG0-00-PP-HE-000006 Bishop 4 - Replace Generator TSO Motors - - 100 100 100 300 121 CG0-00-PP-HE-000006 Kern River 1 Unit 1 & Unit 3 Replace Governors - - - 800 - 800 122 CG0-00-PP-HE-000006 Lundy Install Unit Needle Operators - - - 250 - 250 123 CG0-00-PP-HE-000089 Poole - Replace TSO and Actuator 100 - - 50 250 400 124 CG0-00-PP-HE-000006 Borel - Install Generator on Spare Exciter Header - - - - 50 50 125 CG0-00-PP-HE-000006 Kern River 1 Unit 4 - Replace Unit Governor - - - - 400 400 126 CG0-00-PP-HE-000006 Lundy - Replace Generator TSO Motors - - - - 250 250 127 CG0-00-PP-HN-000025 Northern Hydro Miscellaneous Prime Movers 1,100 1,100 2,200

(Nominal Values are in $1000's) Total 600 1,000 350 2,300 2,150 6,400

REF WBS Element Gates & Valves 2013 2014 2015 2016 2017 TOTAL128 CG0-00-PP-HE-000085 Sabrina - Replace Gate Operator 300 - - - - 300 129 CG0-00-PP-HE-000088 Lundy Lake - Replace Farmers Gate 25 200 - - - 225 131 CG0-00-PP-HE-000038 South Lake Intake - Install Pipe & Valve - 1,100 - - - 1,100 132 CG0-00-PP-HE-000038 Rush Creek - Replace TSO Actuator - 300 - - - 300 133 CG0-00-PP-HE-000038 Bishop - Intake 5 AVM - 250 - - - 250 134 CG0-00-PP-HE-000038 Bishop 2 - Replace Upper Penstock Valve Actuator - 175 - - - 175 135 CG0-00-PP-HE-000038 Abelour - Replace Headgate - 50 - - - 50 136 CG0-00-PP-HE-000038 Bishop 5 - Replace Upper Penstock Valve Actuator - - 175 - - 175 137 CG0-00-PP-HE-000038 Bishop South Fork - Replace Sand Trap Valve - - 150 - - 150 138 CG0-00-PP-HE-000038 Gem Lake - Replace Air Valves - - 80 - - 80 139 CG0-00-PP-HE-000038 Borel Install Penstock AVM's - - - 300 - 300 140 CG0-00-PP-HE-000038 Bishop 4 - Replace Upper Penstock Valve Actuator - - - - 175 175 141 CG0-00-PP-HE-000038 Bishop 3 - Replace Upper Penstock Valve Actuator - - - - 175 175 142 CG0-00-PP-HN-000069 Florence Lake Replace Min. Pool Weir Gate & Release - - - 0.1 - 0 143 CG0-00-PP-HN-000041 Huntington Lake Dam 1 Replace Upstream Valves - - - 750 - 750 144 CG0-00-PP-HN-000041 Florence to Ward tunnel inlet gates & inlet - - 100 1,500 1,400 3,000 146 CG0-00-PP-HN-000041 Camp 62 Replace Valve Actuator - 165 - - - 165 252 CG0-00-PP-HN-000041 Florence lake Dam Drum Gate Replacement - 100 650 1,600 100 2,450 253 CG0-00-PP-HE-000084 Bishop Intake 3 AVM Installation 250 - - - - 250


REF WBS Element Structures Improvement 2013 2014 2015 2016 2017 TOTAL147 CG0-00-PP-HE-000094 Rebuild Birch McGee Intake 250 - - - - 250 148 CG0-00-PP-HE-000078 Kern River Flowline - Rebuild Sandbox 850 2,000 500 - - 3,350 149 CG0-00-PP-HE-000079 Kern River 3 - Dam & Intake Refurbishment 1,150 2,100 500 - - 3,750

(Nominal Values are in $1000's) Total 2,250 4,100 1,000 - - 7,350

DAMS & WATERWAYS

PRIME MOVERS (con't)

B-4

REF WBS Element Dam Surface Protection 2013 2014 2015 2016 2017 TOTAL150 CG0-00-PP-HE-000064 Saddlebag Dam - Wood Spillway Modification 1,600 - - - - 1,600 151 CG0-00-PP-HE-000116 Waugh Dam - Seismic Upgrade/Pressure Grout 350 350 350 6,000 6,000 13,050 152 CG0-00-PP-HE-000082 Gem Lake Dam - Reface Down Stream Side 300 300 4,300 12,000 2,000 18,900 153 CG0-00-PP-HE-000083 Tioga Dam - Install Geomembrane 50 1,100 - - - 1,150 154 CG0-00-PP-HE-000092 Bishop Intake 4 - Resurface Spillway 25 250 - - - 275 155 CG0-00-PP-HE-000027 Bishop Intake 3 - Resurface Spillway - 25 250 - - 275 156 CG0-00-PP-HE-000115 Agnew Dam - Resurface Dam/Seismic Upgrade 650 4,800 - - 5,450 157 CG0-00-PP-HN-000059 Florence Dam Geomembrane Liner - 450 1,250 250 1,950 158 CG0-00-PP-HN-000066 Huntington Lake Dam Geomembrane Liner 200 200 159 CG0-00-PP-HN-000042 Northern Hydro Dam Automation & Leakage Projects 650 500 600 600 2,350 160 CG0-00-PP-HN-000089 Vermilion Dam Monitoring & Drain Improvement 750 299 1,049


REF WBS Element Flowline Replacement 2013 2014 2015 2016 2017 TOTAL161 CG0-00-PP-HE-000096 Santa Ana River 1 - Flume Recoating/Retar 50 - 950 - - 1,000 162 CG0-00-PP-HE-000111 Kaweah 2 - Gunite Canals 250 - - - - 250 163 CG0-00-PP-HE-000099 Alder Creek - Replace Pipe 200 - - - - 200 164 CG0-00-PP-HE-000098 Lytle Creek Flowline - Siphon 4-5-6 Replacement 20 500 500 - - 1,020 165 CG0-00-PP-HE-000113 Tule Flowline - Rebuild 500' of Flume 116 - - - - 116 166 CG0-00-PP-HE-000051 Lytle Creek - Replace Flowline - - 50 200 200 450 167 CG0-00-PP-HE-000014 Tule Flowline Replacement - 120 124 128 132 504 168 CG0-00-PP-HE-000014 Ontario 1 - Siphon 1-2-3-4 Replacement - 20 500 500 - 1,020 169 CG0-00-PP-HE-000014 Kaweah 2 - Replace Steel Flume Sheets - - 300 300 300 900 170 CG0-00-PP-HE-000014 Fontana Penstock - Replacement/Install Coating - - 20 500 500 1,020 171 CG0-00-PP-HE-000014 Lytle Creek Flowline - Siphon 1-2-3 Replacement - - 20 500 500 1,020 172 CG0-00-PP-HE-000014 Kaweah 3 - Replace Upper (Horizontal) Penstock - - - - 1,650 1,650 173 CG0-00-PP-HE-000066 Bishop - Replace South Fork Flowline - - - 150 - 150

(Nominal Values are in $1000's) Total 636 640 2,464 2,278 3,282 9,300

REF WBS Element Major Dams & Waterway Projects 2013 2014 2015 2016 2017 TOTAL174 CG0-00-PP-HE-000037 Kaweah 1 - Flowline Rehabilitation 1,800 1,500 1,500 1,500 1,500 7,800 175 CG0-00-PP-HE-000109 Kern River 3 - Rebuild Tunnel 1,611 5,400 500 - - 7,511 176 CG0-00-PP-HE-000025 Borel - Rebuild Canal & Tunnels 550 550 600 600 1,300 3,600 177178 CG0-00-PP-HE-000015 Kern River 1 - Rebuild Tunnel Phase 5 - - - - 50 50 179 CG0-00-PP-HE-000050 Bishop 6 - Replace Flowline/Install AVM - - - 150 5,000 5,150 180 CG0-00-PP-HN-000070 Mammoth Pool HB Valve Replacement 1,000 1,500 7,903 14,600 3,250 28,253 181 CG0-00-PP-HN-000067 Northern Hydro Dams Seismic Improvements 500 2,100 1,800 1,000 1,102 6,502 182 CG0-00-PP-HN-000068 Northern Hydro Dam Structure Improvement 730 500 500 1,730


REF WBS Element Dams & Waterways - Miscellaneous 2013 2014 2015 2016 2017 TOTAL183 CG0-00-PP-HE-000007 Lundy Clay Liner 50 - - - - 50 185 CG0-00-PP-HE-000102 Borel Forebay Install Crane 200 - - - - 200 186 CG0-00-PP-HE-000007 Santa Ana River 3 - Penstock Upgrade Protection - 300 - - - 300 187 CG0-00-PP-HE-000007 Mill Creek 3 - Flowline Replacement - 50 - - 450 500 188 CG0-00-PP-HE-000007 Kaweah 3 - Resurface Middle Fork Intake - 400 - - - 400 189 CG0-00-PP-HE-000007 Green Creek Diversion Replacement - 250 250 250 - 750 190 CG0-00-PP-HE-000007 Bishop 2 Intake 3 - Install AVM - 250 - - - 250 191 CG0-00-PP-HE-000007 Kaweah 3 - Replace Middle Fork Diversion Dam - 150 - - - 150 192 CG0-00-PP-HE-000007 Lundy Powerhouse Bypass/Install AVM/Headworks - 50 350 - - 400 193 CG0-00-PP-HE-000007 Bishop 5 - Replace Station Cranes - 120 - - - 120 194 CG0-00-PP-HE-000007 Kaweah 1 - Forebay Replace - - 950 - - 950 195 CG0-00-PP-HE-000007 Kaweah 3 - Resurface Marble Fork Intake - - 200 - - 200 196 CG0-00-PP-HE-000007 Kaweah 3 - Gunite Tailrace - - 125 - - 125 197 CG0-00-PP-HE-000007 Rush Creek - Replace Station Crane - - 100 - - 100 198 CG0-00-PP-HE-000007 Bishop 2 - Replace Station Cranes - - 80 - - 80 199 CG0-00-PP-HE-000007 Mill Creek 1 - Spincoat Penstock - - - 20 400 420 200 CG0-00-PP-HE-000007 Ontario 1 - Spincoat Penstock - - - 400 - 400 201 CG0-00-PP-HE-000007 Kaweah 2 - Install Forebay Grid Rake and Conveyor - - - 100 - 100 202 CG0-00-PP-HE-000007 Kaweah 2 - Replace Forebay Spill Chute - - - 95 - 95 203 CG0-00-PP-HE-000007 Kaweah 2 - Gunite Forebay - - - 225 - 225 204 CG0-00-PP-HE-000007 Kern River 3 - Replace Forebay Gate Operators - - - 150 - 150 205 CG0-00-PP-HE-000007 Borel - Rebuild Tailrace - - - - 200 200 206 CG0-00-PP-HE-000007 Kern River 1 Forebay - Install Steel Walkway - - - 600 - 600

DAMS & WATERWAYS (con't)

B-5

REF WBS Element Dams & Waterways - Miscellaneous (con't) 2013 2014 2015 2016 2017 TOTAL207 CG0-00-PP-HE-000007 Bishop 6 - Replace Station Cranes - - - 80 - 80 208 CG0-00-PP-HE-000007 Bishop 3 - Replace Station Cranes - - - 80 - 80 209 CG0-00-PP-HE-000007 Kaweah 1 - Replace Main Gate Valve at Intake Tunnel - - - - 25 25 210 CG0-00-PP-HE-000007 Ontario 2 - Spincoat Penstock - - - - 400 400 211 CG0-00-PP-HE-000007 Bishop 4 - Replace Station Cranes - - - - 80 80 212 CG0-00-PP-HN-000027 Northern Hydro Misc. Dams & Waterways Projects 500 500 1,000


REF WBS Element Building Improvements 2013 2014 2015 2016 2017 TOTAL213 CG0-00-PP-HE-000114 Kaweah 1 - Maintenance/Civil Shop 100 - - - - 100 214 CG0-00-PP-HE-000009 Bishop 4 - Construction Office - 50 175 - - 225 215 CG0-00-PP-HN-000044 Northern Hydro Powerhouse Structure Improvements 825 - - - - 825

(Nominal Values are in $1000's) Total 925 50 175 - - 1,150

REF WBS Element Road Improvement & Paving 2013 2014 2015 2016 2017 TOTAL216 CG0-00-PP-HE-000062 Kern River 3 - Flowline Road Work 2,500 750 - - - 3,250 217 CG0-00-PP-HE-000110 Kern River3 - Replace Adit 19-20 Bridge with Culvert 50 - - - - 50 220 CG0-00-PP-HN-000080 Northern Hydro Road Overlays & Replacement 100 - - - - 100

(Nominal Values are in $1000's) Total 2,650 750 - - - 3,400

REF WBS Element Major Structures & Grounds Projects 2013 2014 2015 2016 2017 TOTAL221 CG0-00-PP-HE-000093 Bishop 4 - Replace Fuel System 575 - - - - 575 222 CG0-00-PP-HE-000090 Bishop 4 - Water System/Install Domestic Well 2,025 - - - - 2,025 223 CG0-00-PP-HE-000046 Rush Creek - Rebuild Tram Track and Replace Tram Car 4,000 5,000 100 - - 9,100 224 CG0-00-PP-HN-000086 Big Creek 1 Camp Cottage Renovations 3,497 - - - - 3,497 225 - - - - - - 226 CG0-00-PP-HN-000087 Big Creek 1 Construct Admininistration/Dispatch Office 8,000 - - - - 8,000

(Nominal Values are in $1000's) Total 18,097 5,000 100 - - 23,197

REF WBS Element Miscellaneous Structures & Grounds 2013 2014 2015 2016 2017 TOTAL230 CG0-00-PP-HE-000086 Bishop 2 - Replace Powerhouse Roof 100 - - - - 100 231 CG0-00-PP-HE-000040 Poole - Replace Powerhouse Roof - 100 150 - - 250 232 CG0-00-PP-HE-000040 Lee Vining - Replace Roof - - 80 - - 80 233 CG0-00-PP-HE-000040 Bishop 3 - Replace Powerhouse Roof - - - 100 - 100 234 CG0-00-PP-HE-000040 Rush Creek - Garage Asbestos Removal - - - 200 - 200 235 CG0-00-PP-HE-000040 Poole Plant - Garage Asbestos Removal - - - 200 - 200 236 CG0-00-PP-HE-000040 Bishop 2 - Garage Asbestos Removal - - - - 200 200 237 CG0-00-PP-HE-000040 Bishop 4 - Garage Asbestos Removal - - - - 242 242 238 CG0-00-PP-HE-000040 Bishop 5 - Replace Powerhouse Roof - - - - 100 100 239 CG0-00-PP-HE-000040 Bishop 5 - Replace Sewer System - - - - 50 50 240 CG0-00-PP-HN-000084 Big Creek 3 Replace Domestic Water Service 50 - - - - 50 241 CG0-00-PP-HN-000092 Big Creek 4 Replace Domestic Water Service 50 - 600 600 500 1,750 242 CG0-00-PP-HN-000090 Florence Lake Replace Camp Domestic Water Line 63 - - - - 63 244 CG0-00-PP-HN-000031 Northern Hydro Misc. Structures & Grounds Projects 2,520 500 1,700 2,200 2,000 8,920 254 CG0-00-PP-HN-000064 Mammoth Pool Powerhouse Covered Storage 260 500 500 600 1,860

(Nominal Values are in $1000's) Total 2,783 860 3,030 3,800 3,692 14,165

REF WBS Element Furniture, Tools & Equipment 2013 2014 2015 2016 2017 TOTAL245 CG0-00-PP-HE-000001 Furniture & Office Equipment 70 - - - - 70 246 CG0-00-PP-HE-000003 Portable Tools & Equipment 150 - - - - 150 247 CG0-00-PP-HE-000011 Lab, Testing & Technical Equipment 238 - - - - 238 248 CG0-00-PP-HN-000017 Misc. Work Equipment and Spare Parts 540 - - - - 540 255 CGO-00-PP-DB-000033 PPD Home Office Computer Equipment 10 - - - - 10 256 CGO-00-PP-DB-000034 PPD Home Office Training Center 40 - - - - 40 257 CGO-00-PP-DB-000035 PPD Home Office E&TS 248 - - - - 248 258 CGO-00-PP-DB-000036 PPD Home Office - Office Furniture 150 - - - - 150

(Nominal Values are in $1000's) Total 1,446 - - - - 1,446

REF WBS Element Decommissioning 2013 2014 2015 2016 2017 TOTAL249 CG0-00-PP-HE-000008 Mill Creek 2 - Decommissioning 200 - - - - 200 250 CG0-00-PP-HE-000017 San Gorgonio Canyon - Decommissioning 376 500 2,000 2,000 2,000 6,876

(Nominal Values are in $1000's) Total 576 500 2,000 2,000 2,000 7,076 2013 2014 2015 2016 2017 TOTAL


STRUCTURES & GROUNDS

DECOMMISSIONING

DAMS & WATERWAYS (con't)

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