silicon valley power integrated resource plan request for

Silicon Valley Power Integrated Resource Plan Request for Proposals Questions and Answers; July 2016

pg. 1

1. Will SVP’s forecast incorporate a forecast of distributed generation penetration and system load impacts? If not, does SVP anticipate such a forecast to be part of the Contractor’s scope of services?

o SVP maintains information on the installed solar photovoltaic systems and backup generation systems in the system. There is no current forecast of future installations. SVP staff will work with Contractor on developing any forecast of distributed generation and related impacts on load that may be required for the completion of the IRP.

2. Does SVP intend for the load forecast to be part of a Contractor scope of work or will a forecast

(at least a base case) be provided for use in the IRP? o A base case trend load forecast based on historical changes in customer profile

and load is available and will be available for use in the IRP. Should a more detailed forecast be required for the IRP, this will have to be developed.

3. What number of Santa Clara staff will be dedicated to the completion of IRP tasks?

o The primary work on the IRP will be completed by two staff at SVP. They will be able to give about 15% of their time to the project. Other staff will provide input and resources as needed.

4. What percentage of Santa Clara staff time will be allocated to the completion of IRP related

tasks? o See answer to question #3.

5. What IRP development tasks does SVP expect to complete themselves in conjunction with the

specific Contractor tasks listed in the RFP? o All tasks listed in the scope will be completed by SVP staff and Contractor

working together to determine what is already available, what can be developed using already available data and what will need to be completed by Contractor. This is a work in progress.

6. When are the results of the IRP due to be presented to the Santa Clara City Council and

California Energy Commission? o By state law, the California Energy Commission must receive the completed IRP

no later than January 1, 2019. Realistically, it must be completed by the 4th quarter of 2018, thus to Council no later than mid-2018.

7. Will Santa Clara staff be providing direction to the Contractor or vice versa?

o In general, Contractor can be viewed as a consultant providing input to staff and completion of projects. In those cases where there are difficulties or some direction is needed, Contractor should view staff as providing direction.

8. What modeling software does Santa Clara staff currently use for econometric load and energy

forecasting?

o Staff uses historical information in databases and excel spreadsheets for econometric and energy forecasting, as well as PLEXOS for generation and production forecasting.


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9. What modeling software does Santa Clara staff currently use for Production costing? o SVP has a contract with a contractor to run PLEXOS models for production cost

modeling.

10. Does SVP have staff that run a specific production cost model in house and if so which production cost model (i.e. PLEXOS, PROMOD, Aurora, Gridview)?

o See answer to question #9.

11. Would consultant provide direction on the running of the production cost model or will consultant run the model off‐site?

o The PLEXOS model is run off-site by a Contractor. 12. When will notification of winning proposal occur?

o By the end of September 2016.

13. Can you provide the expected project schedule (table in Section 6 of the RFP has no dates)?

July 14, 2016 Distribution of RFP August 12, 2016 Deadline for RFP responses August 26, 2016 Select Top 3 Candidates Week of September 12, 2016

Schedule Interviews with Top 3 Candidates

September 30, 2016 Select consultant By November 30, 2016 Professional Services Agreement to City Council Calendar Year 2017 Data Analysis 1Q 2018 Draft IRP Report Mid 2018 Presentation to management and City Council

14. In light of the comment at the bottom of page 5 of 34 indicating “SVP staff will perform the majority of the work on this project with the consultant acting in the role of facilitator and assistant,” please elaborate on what role the contractor will take for each of the tasks listed in the contractor task table shown starting on page 6 of 34.

o This is a work in progress. The actual role played by staff and Contractor will be jointly determined once contractor is selected.

15. Will the contractor take a lead role on any of these tasks or will the scope for the contractor just be facilitator and assistant to SVP staff for each task?

o See answer to question #14.

16. Does the SVP have the requisite modeling software and expertise for the tasks defined in this IRP including:

i.Hourly production simulation models, if so, which software tools i. Hourly generation models are available on a historical basis. PLEXOS production

cost forecasting available. ii.Load, DER and DSM Forecasting models, if so, which software tools.

i. Forecasts on an annual basis are available for load and DSM. iii.Any storage modeling software tools, if so which tools.


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i. No ii. Transmission and distribution load flow, short circuit, transient and flicker analysis models, if so,

which software tools i. Engineering staff uses Aspin – OneLiner, PSLF (a GE program), and ISM

(DEW)

iv. Staff with expertise on the software tools and past experience with IRPs of similar scope. i. Limited

16. On Contractor task, item D, are you referring to the yet to be defined CEC outline associated with Docket 16‐OIR‐Q4, if not, can you please provide a reference to a CEC outline? If SVP is referencing the CEC document expected in Docket 16‐OIR‐Q4, can you provide guidance on what is expected of the consultant for this task when the CEC outline is not yet defined, particularly in light of the not to exceed pricing request?

o Yes Docket 16-OIR-Q4 is being referenced. As mentioned previously, this is a work in progress. SVP staff is assuming that Contractor will have experience in the fundamentals of IRP development to achieve the results necessary for the IRP requirements as they develop.

17. Will the development of forecasts of Demand Side resources (energy efficiency and demand reduction) costs and potential be part of this study or should they assumed to be available input to the study (refer to Contractor Tasks H1 and H5)?

o DSM staff works with an outside contractor to develop costs and potential for DSM resources. This will be an available input into the study.

18. Can you elaborate on what analysis has been completed and what data will be made available to the contractor as it relates to transportation electrification referenced in Contractor Task H7?

o Staff has available meter data for utility owned or placed electric vehicle chargers. It is expected that Consultant will work with Key Account staff to get data for customer sited facilities.

19. Is a proposal for a fixed cost contract an acceptable alternative to the T&M proposal with a not to exceed price, which is discussed in Section 8.1 of the RFP?

o T&M proposals with not to exceed pricing are strongly preferred by the City of Santa Clara.

20. Can you provide a copy or a link to the 2014 SVP IRP and its 2015 Update as referenced by Joyce Kinnear at the April 18, CEC workshop?

o Unofficial, working documents are attached.

Resources Division

CITY OF SANTA CLARA; 2015

SVP’S INTEGRATED ENERGY RESOURCE PLAN

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Table of Contents

1.0 Executive Summary ...................................................................................................... 5

2.0 Introduction and Background ....................................................................................... 7

2.1 The Mission and Fundamental Principles of SVP’s Resource Strategy ................... 7

2.2 Background and Purpose of Policy ........................................................................... 8

2.2.1 Applicability of Policy ....................................................................................... 9

3.0 Energy Resource Planning Strategy and Criteria.......................................................... 9

4.0 Portfolio Scenarios considered in the IERP ................................................................ 10

5.0 Energy Resource Planning Roles, Responsibilities and Organization........................ 11

5.1 City Council ............................................................................................................ 11

5.2 City Manager and General Manager ....................................................................... 11

5.3 Risk Management and Risk Oversight Committees ............................................... 12

5.4 California Agencies ................................................................................................ 12

5.5 Federal Agencies ..................................................................................................... 12

5.6 State and Federal Legislation .................................................................................. 13

5.7 Joint Powers Agencies and Municipal Associations .............................................. 13

6.0 Sensitivity Factors ....................................................................................................... 13

6.1. Cost Variability Risks ............................................................................................ 13

6.1.1. Fuel Pricing ..................................................................................................... 13

6.1.2. CAISO and Transmission Costs ..................................................................... 14

6.1.3. Environmental Issues/Costs ............................................................................ 17

6.2. External Issues ....................................................................................................... 19

6.3. Internal Issues ........................................................................................................ 21

6.3.1. Retail Rates ..................................................................................................... 21

6.3.2. Customer Changes .......................................................................................... 22

7.0 Demand-Side Resources ............................................................................................. 23

7.1 Energy Efficiency ................................................................................................... 24

7.2 Demand Response ................................................................................................... 25

7.3 Customer-Side Distributed Generation (DG) and Combined Heat and Power (CHP)

....................................................................................................................................... 26

7.4 Storage .................................................................................................................... 27

8.0 Eligible Renewables and Carbon Free Supply Resources .......................................... 29

9.0 Supply Resources ........................................................................................................ 32

9.1 Santa Clara Owned Resources. ............................................................................... 32

9.2 Northern California Power Agency. ....................................................................... 33

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9.3 M-S-R Public Power Agency.................................................................................. 33

9.4 M-S-R Energy Authority. ....................................................................................... 33

9.5 Seattle City Light-NCPA Exchange Agreement..................................................... 33

9.6 Western Area Power Administration Purchased Power. ........................................ 33

9.7 Wholesale Power Trading and Market Energy Resources ..................................... 34

9.8 Interconnections and Transmission and Distribution Facilities .............................. 34

9.9 Transmission Rights Owned (through JPAs). ......................................................... 34

9.10 California Independent System Operator (CAISO) Markets. ............................... 34

10.0 Ancillary Services and Other Resources for Capacity Requirements ...................... 35

10.1 Ancillary Services ................................................................................................. 35

10.2 Resource Adequacy .............................................................................................. 36

10.2.1. Reliability Services Initiative (RSI) .............................................................. 36

10.3 Load Following ..................................................................................................... 39

10.4 Phase-Shifting Transformer .................................................................................. 39

11.0 Summary ................................................................................................................... 40

Appendix A: Scenario Analysis Methodology ................................................................. 42

Scenario Details ................................................................................................................ 43

Base Case ...................................................................................................................... 43

Low Load/Costs ............................................................................................................ 46

High Load/Costs ........................................................................................................... 48

Comparison of Supply Costs ............................................................................................ 50

Base Case ...................................................................................................................... 50

Potential Changes to the Base Case .............................................................................. 53

Increase Energy Efficiency ....................................................................................... 53

Add Energy Storage .................................................................................................. 55

Low Load/Costs ............................................................................................................ 57

High Load/Costs ........................................................................................................... 59

Appendix B: Silicon Valley Power Supply resources ...................................................... 62

Santa Clara Owned Resources .......................................................................................... 62

Cogeneration. ................................................................................................................ 62

Stony Creek Hydroelectric System. .............................................................................. 62

Gianera Generating Station. .......................................................................................... 62

PG&E Grizzly Project................................................................................................... 62

Donald R. Von Raesfeld Power Plant. .......................................................................... 62

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Jenny Strand Solar PV System. .................................................................................... 63

Tasman Parking Structure Solar PV System. ............................................................... 63

Jointly Owned Resources .................................................................................................. 63

NCPA Geothermal Project. ........................................................................................... 63

NCPA Combustion Turbine Project No. 1. .................................................................. 63

NCPA Hydroelectric Project. ........................................................................................ 63

NCPA Lodi Energy Center Project. .............................................................................. 64

TANC California–Oregon Transmission Project.......................................................... 64

TANC Tesla–Midway Transmission Service. .............................................................. 64

M-S-R PPA – San Juan. ................................................................................................ 64

M-S-R PPA Southwest Transmission Project............................................................... 65

M-S-R PPA Purchased Power–Big Horn Projects........................................................ 65

M-S-R Energy Authority – Gas Prepay. ....................................................................... 65

Purchased Power Agreements........................................................................................... 65

Altamont Wind Power Project ...................................................................................... 65

Ameresco Landfill Gas Facilities.................................................................................. 66

Friant Small Hydroelectric Projects 1 & 2. ................................................................... 66

G2 Landfill Gas............................................................................................................. 66

Manzana Wind Facility. ................................................................................................ 66

Seattle City Light-NCPA Exchange Agreement........................................................... 66

Tri-Dam Large and Small Hydroelectric Project. ......................................................... 67

Utility Scale Solar Electric Project. .............................................................................. 67

Western Area Power Administration. ........................................................................... 67

Wholesale Power Trading and Market Energy Resources. .......................................... 67

Appendix C: Resource Adequacy Plan ............................................................................. 68

Resource Adequacy Plan Development and Implementation ........................................... 68

Definitions for Resource Adequacy Plans .................................................................... 68

Annual Resource Adequacy Plans ................................................................................ 68

Monthly Resource Adequacy Plans .............................................................................. 68

Supply Plans.................................................................................................................. 68

Resource Adequacy Plan Confirmation ........................................................................ 68

Demand Forecasts ......................................................................................................... 69

Planning Reserve Margins ............................................................................................ 69

Dispatching of SVP Resources by CAISO ................................................................... 70

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Resource Adequacy Qualified Capacity ....................................................................... 70

Local Resource Capacity .............................................................................................. 70

Qualifying Capacity Criteria ......................................................................................... 72

Net Dependable Capacity ......................................................................................... 72

SVP System .............................................................................................................. 72

Jointly-Owned Generation Facilities ........................................................................ 72

Thermal ..................................................................................................................... 72

Hydro ........................................................................................................................ 72

Unit-Specific Contracts ............................................................................................. 73

Firm Physical Contracts ............................................................................................ 73

Wind and Solar ......................................................................................................... 73

Geothermal ................................................................................................................ 74

Treatment of Qualifying Capacity of QFs ................................................................ 74

Dispatchable Demand Resource and Participating Loads ........................................ 74

Facilities Under Construction ................................................................................... 74

Dynamically Scheduled System Resources .............................................................. 75

Non-Dynamically Scheduled System Resources ...................................................... 75

SVP System Transmission Ownership Rights .......................................................... 75

San Juan Generating Station ..................................................................................... 75

Western Area Power Administration ........................................................................ 75

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SILICON VALLEY POWER INTEGRATED ENERGY RESOURCE PLAN Fiscal Years Ending June 30, 2015-2024

1.0 EXECUTIVE SUMMARY

Silicon Valley Power (SVP), the City of Santa Clara’s electric utility, has developed this Integrated Energy Resource Plan (IERP) as a planning document to help guide the utility through a changing environment. This document will be used in planning resource procurement, as a training tool for staff and as an assistance to members of the public who seek to understand decision making processes at SVP.

SVP ran scenarios on its PLEXOS modelling software. A base case was first analyzed. After the initial review, two other scenarios were run using differing assumptions for hydroelectric supplies, natural gas prices, carbon allowance costs, customer demand, Transmission Access Charges (TAC) and differing RPS requirements. SVP followed the required ‘loading order’ and looked at how cost-effective energy efficiency, distributed generation (DG), demand response and energy storage (ES) could meet identified resource needs within the requirements of reliability concerns, customer cost issues, the Renewable Portfolio Standard and greenhouse gas reduction (GHG) mandates. Each of the resource plan scenarios was modeled for cost and power deliverability.

Under the most likely situations, large hydroelectric remains the most economical major supply-side resource for a variety of ancillary services and flexible resource adequacy, but its usefulness as a base resource is limited due to potential for drought and uncertain availability during peak demand periods. Energy efficiency is a very cost-effective resource; however, long-term reliability and continuity of countable savings is doubtful as codes and standards upgrade. Natural gas resources remain the most reliable resource for energy and ancillary services. Whether used to serve customer load or sold into the market, gas remains helpful for the utility’s ability to serve customers reliably and at competitive rates. Periods of drought or major swings in natural gas prices (including carbon allowances) will impact the relative economics of these resources.

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As discussed more fully in Appendix A, under normal operating conditions, there will be period of time when electricity will need to be purchased and others when sales to the market will be required. In general, natural gas resources will continue to be the most favorable for sale—either the fuel itself or, less commonly, the electricity generated from it. Sales are mostly likely expected during normal hydroelectric years during run-off, when hydroelectric resources peak. This early summer effect can be more clearly seen in a graph of one year, 2019 is chosen to exemplify the issue. At those times, the market will likely have sufficient electricity available, and it is most likely that natural gas will be sold into the market. During base and high load scenarios, there will be significant periods of time in the winter when electricity will need to be purchased. If SVP wishes or needs to increase its renewable portfolio, adding wind generation from some locations, similar to Big Horn 2, to the portfolio is likely to fit the need most closely.

Source: PLEXOS Modeling; Base Scenario; November-December 2014

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Assuming that the policy goals in California continue to support demand side resources and carbon emission free generation, without sufficient economic justification to install these measures, increasing amounts of legislation should be expected to require the installation and operation of these costlier environmentally preferred resources. As these required additional resources could be serving a lower utility load due to DG and ES becoming competitive with utility costs and rates, these new resources would strand some existing supply resources and make some current PPAs less cost-effective. In this scenario, the fixed costs in SVP’s system would thus continue to increase while the load base would lessen, thus necessitating increasing rates. The higher priced utility service then would give economic justification for even more customers to install their own DG and ES, which would further increase the amount of stranded SVP assets and lead to lower load requirements over time. In order to ensure that it continues to meet customer needs in an economic manner, SVP should regularly (annually at a minimum) analyze its cost of production for all resources—demand and supply side. In addition, when making resource acquisition decisions, the full portfolio of options should be reviewed with life cycle costs and customer rate impacts as a part of the analysis.

2.0 INTRODUCTION AND BACKGROUND

2.1 The Mission and Fundamental Principles of SVP’s Resource Strategy

The fundamental mission of SVP is to maintain an environmentally sustainable portfolio of resources and reserves that is diverse geographically, by ownership model and in fuel type and is sufficient for reliable electric service at a reasonable cost.

SVP’s recommended resource strategy will meet this mission by following these

fundamental principles:

1. Abiding by the loading order from a diverse portfolio to deliver reliable energy service to customers

2. Meeting or exceeding Renewable Portfolio Standards (RPS) as a tool toward reducing greenhouse gas (GHG) emissions

3. Minimizing cost and risk while keeping retail electric rates as low as practical

4. Deploying and scheduling resources safely and efficiently

5. Complying with Statutory and Regulatory Requirements

To achieve these fundamental principles, SVP will regularly (annually at a minimum) analyze its cost of production for all resources—demand and supply side. In addition, when making resource acquisition decisions, the full portfolio of options will be reviewed with life cycle costs and customer rate impacts as a part of the analysis.

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2.2 Background and Purpose of Policy

SVP is a department of the City of Santa Clara. Since 1896 the department has provided all electric service within the City’s boundaries. Santa Clara is a charter city in the State of California with authority to furnish electric utility service within its city boundaries. The City has powers of eminent domain to contract, to construct works, to fix rates and charges for products or services it provides and to incur indebtedness. SVP operates an electric system which has generation, transmission and distribution facilities. SVP purchases power and transmission services from other providers and participates in Joint Powers Agencies (JPAs) and organizations. The City provides general services to residents, including police and fire protection, as well as water and sewer service. SVP is an enterprise fund, with budgeting separated from that for the City’s general fund. SVP has an obligation to pay the general fund each year a sum equivalent to 5 percent of the utility’s revenues net of expenses, as a contribution in lieu of taxes.

In the 2010 census, the City of Santa Clara’s population was estimated at 118,830.

As of December 2013, SVP served over 52,600 customers, made sales at an annual rate of about 2,978 GWh per year, and experienced a peak demand of about 480 MW. As shown in the graph below, about 88% of SVP’s energy sales are made to industrial customers. SVP delivers roughly 1 percent of power consumption in the State of California. The City’s economic prosperity and quality of life are increasingly reliant upon dependable, high-quality and reasonably priced energy.

Retail Sales by Customer Type in Santa Clara; Calendar Year 2013

This IERP will serve as a planning tool for Senior Management to help guide the utility through a changing environment. It will also provide training for staff regarding the factors that may affect the future of SVP and the industry as a whole. Finally, as a public

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document, it will provide information to members of the public and regulatory agencies as they seek to understand decision making and resource planning processes.

A key objective for the City of Santa Clara is to own and operate the safest electric

utility as possible. SVP follows worker and public safety requirements recommended by various agencies. In particular, OSHA guidelines (as laid out in 29 CFR 1910.137 (b) and related sections) and the California Public Utilities Commission (CPUC) as it relates electrical safety in particular General Order (GO) 95 (Overhead Electric Line Construction), 165 (Transmission and Distribution Facilities) and 174 (Substations). It is the City's intent that the SVP planning reserve policy shall equal or exceed all applicable standards established by the North American Electric Reliability Council (NERC) and the Western Electric Coordinating Council (WECC), and contractual provisions. The City further intends that the policy shall meet or exceed the standard of care in the industry (Good Utility Practice).

SVP will secure and enable delivery of sources of reliable, diversified, cost-

effective and environmentally responsible energy supply and demand-side resources and ancillary services sufficient, according to both SVP’s own assessment and applicable legal or regulatory requirements, to provide this electric service. SVP will also establish planning reserve margins and operating reserve margins that ensure system reliability.

2.2.1 Applicability of Policy

This overall plan applies to all resources procured to meet the needs of the customers served by SVP including long-term and short-term contracts for energy and services; acquisition of generation, transmission and distribution assets; participation in the several joint powers agencies (JPAs) of which SVP is a member; demand-side programs and resources; and SVP’s participation in control area and transmission organizations. While the IERP applies to all procurements and management of the utility’s resources, acquisition of additional supply and demand resources may be made in addition to those mentioned here if these resources become required by additional legislation or regulation, if these resources are found to be cost-effective in relationship to the rest of the portfolio and/or if changes in customer load patterns require new resources. This IERP works together with the Metered Subsystem Agreement (MSS) originally entered into on July 12, 2002 by the City with the California Independent System Operator Corporation (CAISO), and since amended; and as referenced here, the Metered Subsystem Aggregation Agreement (MSSA) between the Northern California Power Agency (NCPA) and the CAISO. 3.0 ENERGY RESOURCE PLANNING STRATEGY AND CRITERIA

SVP’s energy resource planning strategies, methods and processes are consistent with applicable WECC and NERC standards, SVP’s Strategic Plan, the MSS and other relevant contracts into which the City has entered, Good Utility Practice, and sound

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economic and business principles. SVP will continue to maintain an integrated and balanced portfolio of resources that is sufficient to meet its obligations.

Historically, SVP has experienced abrupt increases and decreases in electricity demand, as much as several percent of the total load at a time. The profile of load growth is often “lumpy,” due to new connections, or occasionally, disconnections, of substantial blocks of power-consuming facilities or equipment by industrial customers. This profile is reflective of the high intensity of industrial energy use in SVP’s service area, which is heavily weighted toward high-technology manufacturing and data management facilities.

When procuring resources to serve customer load, risk management processes and procedures are completed following the City’s official Risk Management Policy. SVP also procures fuel for its in-City natural gas-fired generating facilities with supply contracts that are laddered with staggered start times and durations, in order to reduce and limit the effects of fluctuations and spikes in fuel prices. Risk management practices apply to decisions concerning the mix of resources and their loading order, including the decision to use supply or demand-side resources, whether to operate inside Santa Clara versus remote resources, what type of generation to procure and other questions. In general, SVP’s approach has been to maintain a diverse portfolio of generating resources and market energy resources so that it can reduce risk and minimize exposure to loss of generating capacity. Due to SVP’s dependence on transmission services provided by the CAISO and others to bring power from remote locations, SVP is exposed to costs increases and to power delivery interruptions during emergencies or facility failures. SVP continually works to reduce the impacts of transmission cost increases and maintains contingency plans for such occurrences.

Similar to other companies and utilities in today’s business environment, efforts by computer hackers to break into the City’s and SVP’s computers also require SVP to enhance its cybersecurity efforts, as well as continually monitor and improve its physical security efforts. SVP meets all NERC requirements for cybersecurity and physical security and undergoes regular audits to ensure it continues to stay up to date in these areas. 4.0 PORTFOLIO SCENARIOS CONSIDERED IN THE IERP

In order to review potential options for how to deliver electricity to customers in a variety of differing potential scenarios, SVP ran three scenarios on its PLEXOS modeling software. PLEXOS is an energy market modelling and forecast simulation software. First, a benchmarking case was analyzed. The other two variations were run under different scenarios for hydroelectric supplies, natural gas prices, carbon allowance costs, customer demand, TAC rates and differing RPS requirements. A summary of the different variables for each scenario is shown below. Note that San Juan is retired from the mix in all three scenarios after December 2017. More information on each scenario and its major components is included in Appendix A.

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Variable Scenarios

Low Load/Costs Base Case High Load/Costs

Hydro

Low Water—2 droughts (2015- 2016 and again 2020-2021) during the period.

Average Water No droughts—Average water in every year.

Natural Gas Low Price Curve. Average Rate of Increase.

High Price Curve.

Carbon Allowances

Floor Price of Carbon—current price at $11.43 per allowance and increasing at 5% year plus CPI.


$35 per allowance.

Customer Demand (Load)

Drops by 10%--remains lower than historical.

Average—follows historical trends.

High—higher than average due to business growth.

Transmission Access Charge

Expected increases for HV and LV.


Higher due to more wires and more costly construction.

Renewable Portfolio Standard

33% RPS stays through 2030.


Increases to 50% RPS by 2030. Interim requirements increase.

5.0 ENERGY RESOURCE PLANNING ROLES, RESPONSIBILITIES AND ORGANIZATION

5.1 City Council

The City Council is the regulatory body with authority over SVP. The City Council includes the utility in the City’s general plan and approves the budgets for SVP. The legal responsibilities and powers of Santa Clara, including the authority to set SVP’s rates and charges, are held by the seven-member Santa Clara City Council. The members of the Santa Clara City Council are elected city-wide for staggered four year terms. 5.2 City Manager and General Manager

SVP, as the electric utility department of the City of Santa Clara, is under the direction of the General Manager of the Electric Utility who, along with other senior managers of the utility, is appointed by and reports to the Santa Clara City Manager. The City Manager, appointed by the City Council, has the authority to implement this IERP, including delegating to staff the responsibility to carry out policies and ensuring compliance. A primary point of delegation is to the Electric Utility General Manager, whose responsibility is to ensure safe, reliable and proper operations for customer-owners.

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5.3 Risk Management and Risk Oversight Committees

SVP contracts with utilities, merchant generators and other entities engaged in wholesale trading, the supply of energy and services and delivery of demand side programs. SVP’s risk management function is carried out by the Risk Management Committee (RMC), whose members are utility managers and staff. The function is subject to oversight by and regular reporting to the Risk Oversight Committee (ROC), comprised of the Director of the Utility, the City Finance Director, the City Attorney and City Manager. The RMC and ROC follow accepted processes and procedures for managing financial risks. Market trading counterparties from whom SVP procures electricity on the wholesale market are approved only after review of financial condition and ability to perform by the RMC. Credit is extended only to counterparties with investment grade ratings by monitoring agencies (Standard & Poor’s, Moody’s and Fitch). After approval, the RMC monitors the performance and financial condition of counterparties, as well as transaction amounts and positions.

5.4 California Agencies

SVP interacts with state agencies, including the CPUC, the California Energy Commission (CEC), the several regional Air Quality Management Districts (AQMDs), the California Air Resources Board (CARB), and the state Occupational Safety and Health Administration (Cal-OSHA). As a municipal utility, SVP is largely exempt from state agency regulation, but as a practical matter must work with and report to them on various issues.

SVP maintains relationships with the CAISO, as well as California’s three large

investor owned utilities (IOUs), PG&E, Southern California Edison Company (SCE), and San Diego Gas and Electric Company (SDG&E). SVP has not joined the CAISO as a participating generator or transmission owner, but operates under a Metered Subsystem Agreement (MSSA) which enables SVP to use its own schedule coordinator and not be obligated to offer its generation into the CAISO-operated markets except in very limited circumstances. SVP pays a Transmission Access Charge (TAC) to the CAISO for all energy brought into the service territory or the City boundaries. This charge has continued to increase at an alarming rate since the early 2000’s, which has tended to create a benefit for generation within the MSS area, in order to lessen requirements to bring power into the City. SVP also maintains older interconnection agreements with PG&E for delivery of energy over PG&E-owned transmission.

5.5 Federal Agencies

As a municipal utility, SVP is exempt under Section 201(f) of the Federal Power Act from the jurisdiction of the Federal Energy Regulatory Commission (FERC). However, SVP is indirectly affected by actions of FERC, as it exercises authority over California’s three major IOUs and issues orders impacting SVP’s access to transmission facilities. FERC regulates entities from whom SVP procures energy under power purchase agreements.

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Besides FERC, NERC and WECC act in ways that affect SVP’s procurement and market operations. SVP must also work with the federal Occupational Safety and Health Administration (OSHA), the Environmental Protection Agency (EPA) and the Department of Transportation (DOT). 5.6 State and Federal Legislation

State and federal legislation can have significant effects on SVP and its operations. As an example, California Assembly Bill 32 (AB32), enacted in 2006, mandated standards for renewable energy sources as a part of a utility’s resources, raising the required percentage of renewable energy in the delivered total to 33 percent by 2020. AB 32 also mandated reductions in emissions of carbon dioxide and set up a method for carbon trading, which has impacts for future costs and resource mixes. A host of other legislation mandates a variety of requirements on both demand and supply resources. In general, these laws attempt to enhance the environment by increasing requirements on demand and supply resources and reporting requirements. 5.7 Joint Powers Agencies and Municipal Associations

SVP is a member of these JPAs: NCPA, the M-S-R Public Power Agency (M-S-R PPA), and the Transmission Agency of Northern California (TANC). SVP obtains energy and transmission services through the JPAs and bears significant shares of their operating expenses. NCPA provides schedule coordination services to SVP. Along with the Cities of Alameda and Palo Alto, SVP is a member of the Bay Area Municipal Transmission Agency (BAMx), an organization providing consulting services and regulatory comments regarding transmission, capacity and related matters. SVP also is a member of the American Public Power Association (APPA), a national organization of municipal utilities, and of the California Municipal Utility Association (CMUA). 6.0 SENSITIVITY FACTORS

A variety of factors can impact the overall planning process for the utility. Some of the most impactful items, including hydroelectric resource levels, natural gas prices and costs of carbon and transmission pricing, were included in the PLEXOS modeling. Other internal and external factors are also major aspects in the ability of SVP to cost effectively serve its customers. While not all were included in the quantitative analysis, they are included in the review and influence the recommended approach.

6.1. Cost Variability Risks

6.1.1. Fuel Pricing

Forward Energy Prices: Forecasting the prices of energy in the future is a risky business. The pricing of electricity is closely intertwined with the cost of natural gas and other fuels (such as coal), weather conditions, water availability (for hydroelectric

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resources), world geopolitical conditions and so many other variables. When assessing future trends for both electricity and natural gas, the single greatest uncertainty is typically weather. Cold winters and hot summers can dramatically increase demands for energy, which typically results in increases in wholesale energy pricing. Variations in long-term trends, as well as short term spikes, can make large differences in the economics of delivering fairly priced electric service to customers.

Natural Gas Prices: Natural gas usage has grown significantly in the past five or more years, as prices for this commodity have leveled off. In addition to lower prices for natural gas, environmental concerns about coal for generation have increased the role of natural gas in both base load and capacity needs. SVP, as is the case with most electric utilities, purchases natural gas to run several of its facilities. If natural gas cost swing wildly in the future, customers could be subjected to higher electrical prices, depending on the contractual mechanisms and risk avoidance measures implemented by the utility resource planners.

Gas Delivery Charge: SVP pays transportation charges to PG&E for the delivery of

natural gas for generation at the Donald von Raesfeld (DVR) plant and its ownership portion of the Lodi Energy Center (LEC). In January 2014, PG&E filed rate cases that would come close to doubling this charge from 51.5 cents per dekatherm to $1.003 per dekatherm. If approved, the total impact to SVP’s budget for both DVR and LEC generation would be about $6 million per year, or equivalent to a 2% retail rate increase.

6.1.2. CAISO and Transmission Costs

The CAISO manages the flow of electricity across the high-voltage, long-distance power lines that make up 80 percent of California’s and a small part of Nevada’s power grid. The CAISO was designed to grant equal access to 26,000 circuit miles of power lines and reduce barriers to diverse resources competing to bring power to customers, while facilitating a competitive wholesale power market designed to diversify resources and lower prices. The purpose of the CAISO is to act as a traffic controller by maximizing the use of the transmission system and its generation resources, and supervising maintenance of the lines. The CAISO matches buyers and sellers of electricity and related products. The markets managed by the CAISO provide products to meet reliability needs and serve load by providing balancing energy and sufficient capacity and allow participants to meet their own business objectives. Some of the major products and requirements that impact SVP and its ability to deliver electricity at reasonable rates include Ancillary Services, Congestion Revenue Rights, Load Marginal Pricing, Resource Adequacy, Flexible Capacity Requirements and Transmission Access Charges.

Ancillary Services (A/S) Prices: As discussed more completely in Section 10.1, SVP,

as with all Load Serving Entities (LSEs), must provide for A/S, including regulation up, regulation down, spinning reserve and non-spinning reserve.

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Generation Locational Marginal Pricing (LMP): LMP is a way to calculate electricity prices at price points, or nodes, in California’s electricity grid. It gives price signals that are supposed to take into account additional costs of electricity caused by transmission congestion and line loss at points on the grid. Transmission congestion occurs when demand for energy exceeds the ability of the system to move it; for example, when high demand from ‘load pockets’ constrains the transmission system capacity, causing bottlenecks. Load may not be able to get cheaper energy from distant sources. Line loss is when electricity is lost as it travels from generation source to load—the greater the distance, the greater the loss. Congestion and line losses create variations in the actual cost of delivering electricity to different locations. California’s wholesale electricity market is divided into four zones, and each one has a uniform price for congestion. When congestion causes energy prices to rise, the cost is spread to all customers in each LMP.

Default Load Aggregation Point (DLAP)/Sub DLAPs: The design of the CAISO

markets with LMP means that bidding, scheduling and settlement of most customer load is done at the three large default LAPs. Through its Load Granulation process, the CAISO has been looking at further disaggregating pricing into even smaller geographic zones, or sub-LAPs. This process is still under development. If approved, LSEs would bid and settle loads in smaller geographic points. This process, in theory, is intended to send more accurate price signals for transmission investment and demand response. SVP has concerns with how this program might be implemented, as it could be difficult to implement such disaggregated pricing structures and the fairness and appropriateness of the allocation is uncertain. Depending on how such a program might be implemented, there may be impacts on costs and thus customer rates.

Congestion Revenue Rights (CRRs): CRRs are financial instruments issued by the CAISO that allow holders to deal with congestion costs and exposure due to the LMP. Congestion exposure is the difference between the congestion components of the LMPs of two locations (source and sink). CRRs are financial rights to collect/pay for the differences in congestion cost between sources and sinks on the transmission network. CRRs are acquired by entities, such as SVP, primarily to offset costs from congestion in the Day Ahead (DA) market.

There are two types of CRRs: CRR Obligations and CRR Options. A CRR Obligation

(what SVP has) allows its holder to receive a payment if congestion in a given hour is in the same direction as the CRR Obligation, and requires the CRR holder to pay a charge if congestion in a trading hour is in the opposite direction of the CRR. A CRR Option entitles its holder to a payment if the congestion is in the same direction as the CRR Option, but requires no charge if congestion is in the opposite direction of the CRR. CRRs can be allocated or purchased in an auction for long term, seasonal or monthly bases. As an LSE inside the CAISO, SVP is allocated CRRs. SVP can use the CRRs to mitigate some of the financial risk caused by the LMP. SVP’s CRRs entitle it to a CRR Payment if Congestion is in the same direction of the CRR and requires a payment if Congestion is in the opposite direction of the CRR.

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SVP works to mitigate financial risks by monitoring its congestion exposure and

evaluating how its CRRs perform on a monthly basis with a forecasting tool. SVP makes adjustments to its nominations as necessary through its evaluation of the costs and benefits of the monthly allocation process. SVP monitors CRR enhancement activities, if any, at the CAISO, including any expected future impact as the Full Network Model is expanded and the Energy Imbalance Market is implemented.

Transmission Costs: The CAISO charges entities, such as SVP, for bringing in

electricity over the transmission system. SVP, as an MSS, pays charges for the net power requirements of its system—total generation minus the electricity generated in Santa Clara. Thus, locally generated electricity saves a significant portion of costs by avoiding transmission charges from the CAISO. These fees are collected by the CAISO and paid to Participating Transmission Owners (PTO) who own the transmission lines to offset the Transmission Revenue Requirement (TRR) needed to pay for the operating and capital costs as well as a return on investment. The fees are called Transmission Access Charges (TAC) and are divided into High Voltage TAC Rates (HVTAC) and Low Voltage TAC Rates (LVTAC). The same HVTAC charges are assessed statewide to all entities who use the CAISO controlled system on lines at over 200 kV. The LVTAC is assessed on delivery below 200 kV. Rates differ depending on the utility whose lines are being used. Note that LVTAC rates are higher, as they included the CAISO HVTAC and the utility specific LV rates. These charges have increased at a substantial clip since the founding of the CAISO, as utilities and others have continued to build transmission lines to upgrade the system.

Historical and Projected Increases in HVTAC After Founding of CAISO

Source: Navigant Consulting/TANC; January 2015

As shown above, TAC rates per megawatt hour (MWh) have increased dramatically since the imposition of the CAISO. Many of these increased costs were caused by the necessity to update an outdated system. Other new transmission projects were developed to serve new renewable generation located far from load sources, such

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as large scale PV in the desert or wind in the mountains. Some of the cost drivers, however, have come from large cost overruns in the new transmission projects, requirements to provide full deliverability (including Resource Adequacy) from variable and intermittent resources and costs imposed on the system to meet customer demands for undergrounding lines or to avoid environmentally sensitive areas.

Not only have the HVTAC rates increased at a fairly healthy clip since 2001, but

they are projected to continue to increase over time. The High Voltage portion of the TAC charge on its own is expected to increase from around $10 per MWh in 2015 to somewhere between $20 and $40 per MWh in 2024, depending on the amount of cost overrun that approved and likely projects achieve—continuing an ongoing trend that exceeds the rate of CIP growth. TAC charges have become an ever greater part of the cost of serving customers. It is, therefore, an important issue for SVP management to work to keep these costs as low as possible. SVP has lessened its costs by reducing how much energy is brought in over the transmission system and, when it must use the transmission system bringing in electricity generated outside of Santa Clara, to bring in as much of it as possible over high voltage lines.

6.1.3. Environmental Issues/Costs

A number of current and future environmental issues could impact both the costs and operation of electric service at SVP. In order to manage the electric distribution system and customer costs, resource planners analyze the impact to the utility and its customers in a variety of potential scenarios.

Renewable Portfolio Standard (RPS): California has established requirements for

utilities to sell increasing percentages of energy generated at ‘eligible renewable’ facilities. An Executive Order issued by Governor Arnold Schwarzenegger September 15, 2009, required all LSEs to achieve specific RPS requirements ending in a 33% obligation by 2020. These requirements were subsequently codified into law through the passage of SB1X 2 in April 2011. Current law requires renewable energy projects to be “certified” as eligible renewable by the CEC. In addition, the CEC requires output from renewable generation facilities to be tracked through the Western Renewable Energy Generation Information System (WREGIS).

The definition of ‘eligible renewable’ has been made by the legislature and could

potentially change in the future. Proposed Federal and regional requirements are likely to also require substantial use of additional renewable energy resources. Other Western states have adopted differing RPS requirements. SVP has adopted its own RPA related policies and procedures to meet the State requirement. Additions of wind, solar photovoltaic (PV) and other variable energy sources will cause operational changes to the electric grid that may prove costly to deal with at the individual utility level. Further increases in the required RPS would likely increase the risk for operational and/or cost issues for SVP.

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Renewable Energy Credits (RECs): A REC is the property rights and legal ownership to the environmental, social, and other nonpower qualities of renewable electricity generation. A REC, and its associated attributes and benefits, can be sold separately from the underlying electricity associated with a renewable-based generation source. RECs are tracked by organizations, such as WREGIS, to ensure that they are appropriately tracked from generation to retirement. RECs provide buyers flexibility in procuring green power across a diverse geographical area and in applying the renewable attributes to the electricity used at a particular location. In California, CEC eligible RECs may be used to meet a certain portion of the RPS requirement. The cost of RECs varies based on supply and demand. The potential exists for large pricing increases or lack of REC availability.

Carbon Pricing: In order to reduce carbon and other greenhouse gas emissions,

California is one of several political entities that has developed a method to charge those who emit this gases. Carbon pricing usually takes the form of a carbon tax or a requirement to purchase permits to emit (also called "allowances"). In California, the cap and trade system includes allowances that are tradable and are limited annually to a certain number that is reduced each year, with the goal of making long term reductions in greenhouse gas emissions.

Regulations promulgated by the California Air Resources Board (CARB), under

state law (AB32), have the effect of taxing the imports of electricity to California based on CO2 emission levels. The law set up a Cap and Trade market for carbon allowances and is in effect until 2020. After 2020, what will happen with Cap and Trade and related legal mandates is unknown. Although it is likely that some type of system will continue, the numbers of allowances, their pricing and how this will impact the cost of electricity is still very uncertain. Potentially, a more restrictive system without free allocations to utilities who made early environmentally positive investments could be required. Without free allocations, there could be an impact on electricity costs to the customer.

CARB distributes allowances through an allocation process. These allowances can

be allocated freely, sold, or distributed in some combination. SVP receives free allowances for early adoption of eligible renewable resources, which is defined as investment in eligible renewable energy resources between 2007 and 2011. Credit for early action is capped at 25% of the expected cost burden. SVP sells and buys allowances as a utility with generation sources that emit greenhouse gases. Allowances are tradable in a market, so they have value whether they are auctioned or freely distributed. The proceeds from allowances auctions are used for a variety of purposes based on State law.

Allowances do not expire, which allows SVP or any other entity to hold any

‘excess’ in a bank until they are needed. SVP has been banking allowances since the beginning of the Cap and Trade system, as it has exceeded state requirements in the RPS. This banking allows SVP to save allowances across compliance periods, which limits risk for higher prices in the future. Another risk that is limited through banking is the

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possibility that the state may require a greatly increased RPS in 2020 or soon after. Having a bank of allowances will give SVP time to avoid rushing into high cost or risky resource contracts while remaining in compliance with AB32 requirements. SVP has built up a large number of allowances in its bank and may want to review whether it should set an upper limit on how much can be banked in the future.

The price for carbon allowances has settled at slightly above $10 per ton of CO2,

which is added to the cost of power for those resources that come from GHG emitting facilities. Major changes in the price of carbon allowances will impact future comparative economics for generation facilities, as well as overall rates to customers. As can be seen below, auctions have, to date, kept prices relatively stable:

Date of Auction Current Year Clearing Price Three Year Out Clearing

Price

February 16, 2013 $13.62 $10.71

May 16, 2013 $14.00 $10.71

August 16, 2013 $12.22 $11.11

November 19, 2013 $11.48 $11.10

February 19, 2014 $11.48 $11.38

May 16, 2014 $11.50 $11.34

November 25, 2014 $12.12 $12.12

The US EPA proposed a Clean Power Plan in 2014. The goal of this plan is to cut

carbon pollution from power plants. US EPA's proposal differs from state to state in its requirements. Barring delays caused by legal challenges, the US EPA is expecting to finalize the Clean Power Plan by mid-2015. Federal legislation that could regulate the emissions of greenhouse gases and may or may not preempt state or regional regulation is not considered likely in the near future. 6.2. External Issues

There are many external issues that could impact the ability of SVP to deliver electricity to its customers, both from an operational and a pricing sense. Among the most important of these are weather, legislative action and regulatory oversight.

Weather: Changes in electric demand are greatly impacted by weather patterns.

Changes in long-term weather patterns and short-term variations can both create havoc in utility planning, increasing the requirement for modeling various scenarios to ensure adequate supplies are available, while at the same time having the ability to sell, preferably at a gain, any over capacity that may be available when demand is low.

Weather patterns impact load, supplies and prices in the utility business. For

example, a particularly long heat wave can impact the availability of electricity and its pricing, causing sharply increasing demand, supply shortages (for instance for hydro

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power which is less available in hot and dry conditions), as well as related price spikes in the market. On the other hand, prolonged cold spells, particularly those that impact beyond the ability of storage facilities to adequately provide for, can cause large demand increases, supply shortages and huge price spikes. One of the major forces of weather on utilities in the west is the impact of drought on hydroelectric generation. Statewide, anywhere from 14 to 19 percent of California's energy is provided by hydroelectric generators both inside and outside the state. Hydropower dams in California have the capacity to generate 14,000 MW annually1. On average, 25,000 gigawatt-hours (GWh) are generated. In a dry year, about 15,000 GWh of energy are produced (roughly the same as solar) and in a wet year, about 40,000 GWh can be generated. When the state is in a drought and has a smaller snowpack, less electricity can be generated by these facilities, increasing the demand, and likely price, for electricity from other sources, such as natural gas and renewable facilities.

Legislative: Laws are made in the legislative branch of government—Congress at

the federal level and the State Legislature in California. These laws can and do impact the electric industry on a variety of levels. The restructuring of the utility business in 1996 with the Electric Utility Industry Restructuring Act (AB1890) or the imposition of a cap and trade system for greenhouse gas emissions in the Global Warming Solutions Act (AB32) are prime examples. At the Federal level, the Clean Air Act of 1970 has been used as the basis for many regulations to deal with air pollution, some of which have had cost and/or operational impacts on electric generation and the utility as a whole. Typically, additional laws, at a minimum, require more reporting and directions on how the utility will operate, which, whatever the beneficial impact or intent of the law, does tend to increase costs. SVP works with other utilities and agencies to monitor these processes and provide input in the development of new laws.

Regulatory: A regulatory organization is a governmental agency responsible for

exercising autonomous authority over a particular activity in a regulatory or supervisory capacity. Some regulatory agencies are independent from other branches or arms of the government, such as the CAISO, while others have closer legislative oversight of activities. Agencies deal in regulation and rulemaking to codify and enforce rules while imposing supervision or oversight over their particular area. For example, the CEC determines whether, where and with what restrictions generation facilities over 50 MW can be built in California. CARB has very detailed rules with requirements for utilities and others on how they must report greenhouse gas emissions.

An effective regulatory agency works for transparent decision-making, including

consultation and participation by a diverse group of parties, and requires its administrators to explain the reasoning for actions, while promoting non-arbitrary and responsive decision making. Most agencies also allow for review of administrative decisions by courts. Environmental laws and policies are administered through regulatory

1 http://www.energy.ca.gov/drought/drought_FAQs.html

http://www.energy.ca.gov/drought/drought_FAQs.html

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agencies, such as the CEC and CARB at the state level and EPA at the federal level. Some rules from these agencies, such as the EPA’s proposed Clean Power Plan, may have sweeping impacts throughout the industry and the country. Others impose reporting or operational requirements that could potentially impact the utility and its customers in unforeseen ways. SVP continues to work with regulatory agencies on its own and through its JPA’s to help provide necessary feedback in the consultation and participation process to attempt to reduce unnecessary, negative and costly impacts. 6.3. Internal Issues

6.3.1. Retail Rates

SVP has a fairly flat load shape and high system load factor (over 70%). Projections for the next 10 years suggest this load factor could go even higher, if the current customer mix remains the same. The need to purchase additional “on-peak” resources or shift usage off peak to avoid high cost energy is quite muted compared to the majority of electric utilities. However, with changes in the industry due to more variable and intermittent energy generation sources and the quick ramping grid need when these resources differ from usage patterns, including high peaks from more air conditioning, electric vehicle charging and so on, SVP may look to add and/or modify its pricing strategy to better align customer usage with supply availability.

Cost of Service study: Cost of service studies are a basic tool in utility ratemaking.

These studies identify how much it costs to deliver each function for all major customer classes based on their load and service characteristics. A cost of service study analysis can provide a useful guideline for assigning cost responsibility to each customer group to avoid price discrimination. SVP has not performed a cost of service study in over 15 years, but one is underway now. It is likely that after completion of the current study, there will need to be rate adjustments between classes and between different types of charges. For instance, it is possible that the residential class may have been subsidized by industrial customers or that fixed costs have been billed through volumetric rates. Dealing with such changes will likely take some time and communication with customers, but should result in a more appropriate fees for customers and cost recovery for the utility.

Tiered Rates: Tiered rates are a common tool in utility pricing. These rates charge

different prices to customer depending on the amount of energy they use. To encourage conservation, it is common for utilities to charge more per unit as usage increases during a billing cycle. IOUs in California have had fairly steep tiered rates, where the per-unit charge goes up dramatically as usage increases. SVP has not significantly tiered its rates, but will look at the impact of such rates after it completes the cost of service study.

Variable Pricing: Many utilities with significant peak loads have developed rate

structures to provide financial incentives for customers to reduce their load at peak times. There are several types of variable pricing, including time of use (TOU), Critical Peak and

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Real Time pricing schedules. In TOU rates, by far the most common type of variable pricing, electricity prices are set for a specific time period on an advance or forward basis, with higher rates during peak periods. The goal is to allow customers to vary their usage in response to such prices and manage their energy costs by shifting usage to a lower cost period or reducing their consumption overall. While TOU rates have become popular as an attempt to provide appropriate economic signals to customers on when to use power, the cost differential for SVP to provide service at different time periods is very small. In January 2009, SVP established a TOU rate based on its cost, but because of the small differential there are no significant economic benefits to switching from standard rates.

Critical peak pricing has higher prices to reflect the costs of generating and/or purchasing electricity at the wholesale level at specific times. Real time pricing is a rate methodology to change customer rates in relationship to what is happening on the wholesale market. SVP may look to add and/or modify TOU pricing packages for its customers, particularly those with large and spiky loads, such residents with Electric Vehicles (EVs), to incent them to use the system when it is most advantageous to the utility and, thus, its customers.

6.3.2. Customer Changes

A number of individual and general changes in customer usage and involvement with the utility could impact operational and rate requirements in Santa Clara, as well. The most likely factors are briefly summarized below.

Changes in Customer Loads: For many years, SVP has had a steadily increasing

growth in load, primarily driven by large customers that tend to use electricity evenly throughout the day and year around. This increasing load, as well as its relatively even pattern, has been a large factor in allowing SVP’s costs to remain competitive with other utilities in the state. Should loads increase or decrease substantially, or change in pattern to a more “peaky” nature as is typical of many utilities, this will impact SVP’s ability to provide service at low rates. If SVP’s load were to dramatically increase or decrease, rapid changes in its generation mix and portfolio would have to be made that could substantially increase costs for customers. Also, if significant amounts of residential and commercial load are added, peak resources would be necessary to meet this requirement.

Direct Access: Direct Access (DA) is an optional service that allows customers to purchase electric supplies and additional energy services from a competitive Energy Service Provider (ESP), rather than from the traditional utility. The electricity is purchased from the ESP, but the utility continues to deliver the electricity through its transmission and distribution systems. While IOUs in California were required to allow customers to have DA service during the restructuring of the industry in 1998, the ability of retail customers to acquire DA was suspended on September 20, 2001 after the energy crisis. SVP has not yet authorized DA in its service territory. In the current energy market and with the addition of Community Choice Aggregation in other areas of the state and authorization for them to exist statewide (see below for information on CCAs), SVP has

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received requests to allow DA. SVP is reviewing whether to authorize this capability and, if so, how to set up rates in a way to keep customers who do not participate in DA from being harmed economically by those accessing this option.

Customer Choice Aggregation (CCA): CCAs are a type of direct access. CCAs allow an organization other than the local utility to aggregate the buying power of individual customers to get energy supply contracts and provide customers with energy on a community-wide basis. CCA's are a new type of utility that aggregate regional energy demand and negotiate with competitive suppliers and developers. A number of CCAs have been set up in California, such as Marin Clean Energy and Sonoma Clean Power. These have been focused on allowing customers to purchase carbon free and/or renewable energy at rates that are competitive with their utility. CCAs are currently filling a need of some customers for environmentally positive energy sources at competitive prices. The long term viability of this option and impacts on utilities, as well as other customers, is something that SVP will continue to monitor. Cogenerator Steam Unit: Since 1981, SVP has provided steam to an industrial customer with its turbine located inside Santa Clara. The contract is typically renegotiated every three years. Under the contract, Santa Clara provides system electric service to the customer under a contract rate and sells steam back. The industrial customer processes the blow down from the 7.4 MW facility. If there was no longer a need for the customer to receive the steam, the cogenerator would likely be shut down, as it is an older peaking unit that is inefficient, and the costs to provide the service are roughly equivalent to the revenue received from the customer.

7.0 DEMAND-SIDE RESOURCES

To ensure grid stability, electricity supply and demand must remain in balance in real time. Utilities, such as SVP, have traditionally used peaking power plants to ramp generation up and down to match load variations. In the state’s ‘loading order,’ utilities are now required to first look at cost-effective energy efficiency/demand side management (DSM) and renewable resources when the resource portfolio needs to be enhanced. DSM includes energy efficiency, distributed generation, demand response (DR) and energy storage. It works from the other side of the resource equation: instead of adding more generation to the system, it uses a variety of technologies to get energy users to reduce consumption.

As demand is becoming a bigger side of the utility-customer equation, utilities are

planning for a paradigm shift electricity delivery. Historically, the energy business has had a top-down, one way delivery and communication mechanism controlled through central dispatch. With the development of a more robust communication technology and infrastructure along with changing customer expectations, the industry is shifting to one where both energy and information will flow both ways between the customer and the utility grid. SVP’s current platform utilizing a fiber optic backbone and local WiFi internet

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capabilities to deliver communication services within its system and to customers is expected to be expanded to enable grid automation, monitoring and control at a granular level not seen previously.

SVP’s Fiber Enterprise currently provides leasing services to business and telecom

customers, supports the Santa Clara Unified School District and is integral in the “SVP Meter Connect” customer information program. It also provides the communication infrastructure throughout the utility’s substations and equipment and will be the backbone for the Automated Meter Information (AMI) system when it is fully implemented. For many of the large industrial customers who are fiber carriers and data centers, this system is a critical venue between Bay Area internet exchange center routes. With the on-going development of virtual “cloud” computing, broadband services and social networking, Santa Clara will continue to be an important venue for communication technologies.

In the future, many customers will generate power for both their own use and to

sell back to the grid. Electric vehicles (EV) use batteries to power transportation and are charged from grid. EV batteries and other energy storage devices will help to smooth out imbalances between supply and demand, providing services traditionally done by peaking power sources. Customers will be presented with a variety of pricing and efficiency programs to gain their assistance in this effort. Sophisticated communication and computer systems will help to integrate these facilities into one reliable grid.

SVP is interested in helping to shape this future by working with customers to

expand its sustainable, reliable and reasonably priced utility services into new and future clean technologies. While the market does not currently support many of these technologies at a commercial and economical level, SVP is and will continue to be implementing pilot projects on a variety of fronts. These pilot projects will give staff and systems experience in developing and administering new programs, so that it will be able to provide these new technologies when they do become operationally and commercially viable. While some of the technologies are likely to become integrated into the utility over the next 10 years, which ones will mature and on what time scale is as yet to-be-determined.

7.1 Energy Efficiency

Energy efficiency (EE) is designed to avoid waste in electricity usage by having customers purchase and/or install better quality equipment and appliances for use in homes and businesses. Behavior changes to avoid waste are also encouraged. These programs are funded by means of the Public Benefits Charge applied to and collected through customer bills. In Santa Clara, these funds averages about $8 million per year. Over 272 million kilowatt hours in cumulative “first year” savings have been achieved since 1998. SVP sets efficiency targets for the upcoming 10 years on a tri-annual basis, with the last targets set in 2013. At that time, based on an analytical review of technical,

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economic and market feasibility, as well as customer’s knowledge of and willingness to adopt these new practices or equipment, the 10 year goal for EE programs was set to reduce electric demand at a rate of 0.66% of the total load on average per year. Santa Clara also pursues opportunities to reduce its own power consumption, serving both the City government and the utility. These City programs include incentives for and assistance with upgrades in lighting for streets and buildings, as well as equipment upgrades.

The level of reportable energy savings from these EE programs as a percentage of

load fluctuate over time. New, efficient technologies are developed that customers will grow to accept and adopt. SVP can assist customers in adopting these measures through rebates and other incentives. Over time, new technologies become an expected part of operation and are adopted into codes and standards. Once required, the utility is then no longer able to record savings. This leads to ‘lumpy’ reported program savings on a year by year basis. However, even though SVP is not always able to record savings as achievements of its EE programs, customers continue to have more efficient homes and businesses and load increases are reduced.

The programs offered to customers include the following areas:

Residential

Rebates for LED light bulbs, efficient refrigerators, attic insulation, air conditioners, ceiling/whole house fans and electric heat pump water heaters.

Recycling of old refrigerators and window air conditioners.

Low Income Holiday LED Light Exchange and refrigerator replacement program. Commercial & Industrial

Commercial rebates for lighting, HVAC, variable frequency motor drives, food service equipment, power management software and plug load sensors.

Performance-based incentive for controls systems under a pilot program (requires demonstrated energy savings over 5 years and makes payments annually upon submission of a verification report).

Data Center efficiency and airflow optimization programs.

New construction incentives.

Public Facilities' energy efficiency rebates, technical assistance and loans with on-bill financing.

Customized projects and savings.

SVP annually has a third party agency verify program savings. In Fiscal Year 2013, the programs saved over 15,475 MWh in gross annual savings, at a benefit cost ratio of 1.63 (where ratios greater than 1 are cost-effective). 7.2 Demand Response

Demand response (DR) occurs when customers reduce their load in response to a request from a utility. It is essentially equivalent to adding generation, since DR can narrow or eliminate gaps between loads and available generation, as though the energy

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saved was actually available and delivered. DR is counted as a resource for serving load. The design of SVP’s utility infrastructure does not currently provide significant incentives for customers to participate in DR programs. Over the next 10 years, it is likely that with the increase in variable energy generation from certain renewable sources, high demands from EVs and other new technologies, the market for DR will become increasingly more positive in SVP’s service territory. SVP plans to continue to develop pilot projects, so that it can develop the capabilities to implement these programs in an effective manner that incentivizes participants while not punishing other customers.

SVP’s customer participation incentives for DR programs are slightly lower than

overall electric rates. One major customer has entered into a formal interruptible or demand response contract, giving SVP authority to curtail service to that customer up to 20 times per year for a limited number of hours due to economic or system emergency needs. This one customer can provide eight to ten megawatts of interruption when called upon. Key Account Representatives believe that there may be some other customers who have an interest in a similar DR program, if pricing is sufficiently high and customers can either drop off large blocks of usage or divert the load to a clean self-generation facility. Modifying the rate design would enhance customer benefit for participation. 7.3 Customer-Side Distributed Generation (DG) and Combined Heat and Power (CHP)

Another way to reduce system demand is by generating electricity inside the utility’s system at smaller facilities through DG, which can be solar panels or other small generation at customer sites or cogeneration facilities (combined heat and power or CHP) located on customer sites. In the next 10 years, more of these technologies will be in use throughout Santa Clara and other utility territories in California, requiring changes in system control, operations and communication. These changes will necessitate a robust communication infrastructure, including the fiber network, city-wide WiFi capability, Automated Meter Information systems and the implementation of a variety of other technologies.

Adding more DG, both net metered and as utility owned generation sources,

creates a more complex distribution system that will have operational and cost issues for SVP. According to a study completed in September 2014 by the CEC and Navigant Consulting,2 the cost of installing and integrating DG into the electric grid depends highly upon locational factors for both the distribution and transmission systems. Generally, integration impacts and costs are lower when DG is installed in urban areas. Integration costs increase significantly as greater amounts of DG are clustered and/or installed near

2 Distributed Generation Integration Cost Study: Analytical Framework, (September 2014), California Energy Commission and Navigant Consulting, CEC-200-2013-007. Note: The study used the SCE system is used as host and assumed that the statewide goal is achieved by 2020 (including existing DG). The largest single DG unit is 20 MW, but most were assumed to be rated at 10 MW or less. System benefits provided by DG are not included in the evaluation. Integration costs included DG interconnection costs, as well as system and bulk transmission system upgrades.

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the end of distribution lines. Policies that encourage DG in areas with fewer impacts will minimize grid integration costs and thus increase benefits.

For the past 15 or more years, SVP has had a practice of encouraging local PV DG

installations. Several PV installations and power purchase agreements currently are at a total of combined capacity in-town of 0.5MW. Customers are also encouraged to install on-site systems through SVP’s PV rebate program. Customers have installed a total capacity of about 10MW in PV systems inside Santa Clara.

Customers typically receive rebates, income tax credits and net metered rates

when PV systems are installed. Net metering means that when a PV system produces more than the customer uses, the meter runs backwards. The customer may then draw electricity from the utility system at a later time at retail level rates. Industry-wide, there is the concern that relatively wealthier customers install PV systems and avoid paying for the portion of the transmission and distribution system they still require when they are not producing. If rates are not designed appropriately, nonparticipating (and likely poorer) customers end up subsidizing these costs. If the group that does not have PV systems increases, other customers over which these system costs would need to be spread would decrease, causing ever increasing rates for this group. Such a ‘death spiral’ can be avoided by ensuring that fixed costs for the system are appropriately included in fixed and non-bypassable fees, while variable costs are charged through volumetric rates. SVP will need to monitor DG installations and design rates to ensure that no arbitrary cost transfers occur between customer groups.

SPV also operates a 7.4 MW cogeneration unit (described in the Santa Clara

Owned Resources section) and is investigating other possible combined heat and power (CHP) projects to help supply load growth. CHP installations make use of the fuel burning and steam production to provide heat energy and electric power to the cogeneration partner. This dual production allows substantially higher fuel efficiency ratios. 7.4 Storage

Energy storage (ES) absorbs energy, stores it for some period of time (at a loss) and then releases it for use. ES can provide system flexibility when supply and demand are not in balance, such as during peak periods of variable renewable generation. The most common sources include hydroelectric facilities, rechargeable batteries, thermal energy storage (TES) and compressed air systems. By far the largest amount and most cost-effective ES in use world-wide is pumped hydro. Batteries are becoming more commonly cited as useful parts of the future distribution smart grids. The batteries used to provide backup for distributed solar PV systems and EVs could provide reliability and system stability benefits in a world with great use of variable energy resources.

ES can be used by utilities in various way, including some of the following:

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Time-of-Day Arbitrage: ES charged when electricity prices are lower (usually off-peak periods) and discharged when prices are higher (typically on-peak periods).

Peak Capacity: A storage system would serve peak load and reduce the need for additional traditional generation.

Ancillary Service: ES could provide regulation, spinning and non-spinning reserves and to free up capacity on existing supply resources for other uses or to reduce the need for more generating capacity.

Load Following and Renewable Integration: To ensure customers are served when they need power, supply must be constantly varied to match demand. This constant change in output can strain power plants. Variable resources like wind or solar create other challenges in balancing supply and demand. ES can be operated to smooth out supply needs in either instance.

Voltage Support: ES could help to maintain the electric grid’s voltage.

Black Start: During catastrophic grid failures, a fully charged ES device would energize the grid and provide station power, so generation could be brought back on-line.

Transmission and Distribution (T&D) Upgrade Deferral: ES could serve a portion of the load during the few peak hours in a year, thus delaying and possibly avoiding T&D upgrades.

None of these capabilities currently has much cost-effective value for SVP. Most

ES technologies are still maturing and remain relatively new and expensive. Because the City is mostly built-out, siting ES will be difficult, as many are space intensive and difficult to site in urban settings. For example, a 5 MW battery system needs enough space for five semi-trailer sized containers, in addition to all the wiring and balance of plant to connect the batteries to a substation. Peak reduction is another primary use for energy storage systems, but due to SVP’s relatively flat load profile and its fully resourced supply portfolio, this is not a great benefit for SVP. Use of ES to improve reliability is not currently needed by SVP. Customers who want to increase their own reliability or decrease bills already have business justifications and can purchase backup systems, generators or Uninterruptible Power Supplies (UPS) without a utility procurement target. Thus, installing large scale ES systems based on utility need cannot be justified at this time.

State Law (Assembly Bill 2514) requires publicly owned utilities to evaluate the

use of ES as an element of power supply plans by adopting an Energy Storage Procurement Plan. Prior to the current plan’s adoption on August 19, 2014, SVP reviewed various technologies and their relative cost effectiveness in the current marketplace. This review found that ES technologies at this time were not cost effective with the exception of large pumped hydro storage, which is very sensitive to particular geographic locations. To satisfy SVP’s obligations under state law, the City Council approved the following energy storage procurement targets in August 2014:

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Category Amount (kW) / Reason

Transmission None – not cost effective

Distribution None – not cost effective

Customer 30 kW – Green Charge Networks at Tasman Parking Structure

SVP is piloting an ES project at the Tasman Drive Parking Structure through a CEC grant designed to reduce customer-side peak demand charges from high energy EV fast charging. Other EV chargers in Santa Clara may be added with such storage capabilities in the future. SVP has also been approached by other start-up energy storage companies that are interested in testing and evaluating their technology in cooperation with SVP. These projects provide an opportunity to study different energy storage projects, their impacts on the utility system and their cost effectiveness. SVP will continue to evaluate ES technologies, particularly those that might include evaluation Vehicle-Grid-Interface (VGI) options using EV or solar PV batteries to support the distribution system. As these systems become more cost effective in the market, more customers will install them. Enhancing SVP’s communication technology capabilities will allow the utility to coordinate these distributed systems into the management of the distribution system. As SVP does not know when these opportunities might arise, they were not incorporated into the ES procurement target. 8.0 ELIGIBLE RENEWABLES AND CARBON FREE SUPPLY RESOURCES

To enhance reliability, environmental responsibility and price, SVP has a diverse portfolio of generation sources. When making resource acquisitions, SVP considers whether needs could be supplied through demand side opportunities, renewable energy or traditional supply resources. To ensure that all costs are included in the equation, carbon allowance pricing is added to supply resources when making acquisition decisions. This decision metric combined with its long-term history of concern for the environment and the relatively recent RPS requirements has led SVP to pursue a portfolio that has a broad array of resources, including high percentages of energy from carbon free and renewable facilities. While state law currently requires utilities to achieve 33% of their power mixes from eligible renewable sources by 2020, SVP has already reached that goal. For Fiscal Year ending June 2014, in addition to demand-side programs and their capability to reduce overall load requirements, as well as make additions to the portfolio, the SVP supply resources mix is over 40% natural gas, 18% large hydro, 14% wind and 11% geothermal, with smaller amounts coming from coal, small hydro, landfill gas and solar photovoltaic sources, as estimated and shown below.

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SVP Supply Resources Mix; Fiscal Year Ending June 2014

Projected SVP Supply Resources Mix in 2018; With Known Resource Changes

To help maintain this wide variety of resources, Santa Clara participates in JPAs,

owns generation outright and has contracts for purchase, both long term and on the spot market. The diverse portfolio from various types of facilities, with different ownership and contracting models, as well as the diverse geographic area from which the power comes has served Santa Clara well for decades. SVP has met its overall objectives of providing reliable power to its customers at comparably low rates while maintaining a positive environmental profile. Most utilities throughout the state have worked to ensure a diverse portfolio exists. As the chart below shows, this diversity has remained over a number of years, with some decrease as coal and nuclear have gone down while some renewables and combined cycle natural gas generation have increased.

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California Total Historical System Power

State law, under the RPS, requires LSEs to serve customers with defined and

increasing percentage levels of qualified eligible renewable resources in their power mix. Eligible renewable resources are not necessarily the same as carbon free generation (resources that emit no GHG emissions). In California, eligible renewable generation is defined to include the following resources: biodiesel, biogas (including pipeline biomethane), biomass, conduit hydroelectric, digester gas, fuel cells using renewable fuels, geothermal, hydroelectric (under 30 MW), landfill gas, municipal solid waste, ocean wave, ocean thermal, and tidal current, photovoltaic, solar thermal electric, and wind. Note that it does not include two types of generation that do not emit GHG and thus are carbon free—hydroelectric facilities over 30 MW and nuclear. SVP has no nuclear resources, but does have large hydroelectric resources for energy, capacity and A/S. SVP’s expects that it will continue to achieve or even exceed mandated levels of renewable generation in the mix. The graph below shows SVP’s projected renewable procurement through 2022 under the base case scenario.

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9.0 SUPPLY RESOURCES

SVP has a diverse supply portfolio and is active in the wholesale power markets. It maintains resources as its own entity, through JPAs and through Purchase Power Agreements (PPAs). A full description of each of these resources is given in Appendix B. This IERP addresses how SVP’s supply resources will meet the load requirements of customers in the next 10 years. The plan looks at how SVP’s reliability needs will be met, power, as well as Resource adequacy and dependability of service in fact. The issues regarding reliability can all be summarized as the need to be able to bring in the energy resources identified as necessary to meet SVP’s obligation to serve load.

9.1 Santa Clara Owned Resources.

SVP operates within the CAISO’s control area under a MSSA with the CAISO, allowing SVP to use its own schedule coordinators to arrange for delivery of energy from remotely located resources and/or to outside customers. The City owns facilities for the electric power distribution in its limits (approximately 19.3 square miles), which includes about 29 miles of 60 kV power lines, approximately 510 miles of 12 kV distribution lines (64% of which are underground), and 24 stations. SVP’s generation and transmission assets are not under the CAISO’s control. The City’s facilities, more fully described in Appendix B, include

A cogeneration plant--steam for sale to a paperboard plant and delivers power to the distribution system.

Stony Creek Hydroelectric System--three hydroelectric dams near Willows and Orland.

Gianera Generating Station--a small natural gas and fuel-oil peaking plant.

Grizzly Dam project in Plumas County, California.

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Donald Von Raesfeld natural gas plant in Santa Clara.

Solar PV in Jenny Strand Park and Tasman Parking Structure in Santa Clara. 9.2 Northern California Power Agency.

The City, together with the Cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Redding, Roseville and Ukiah, the Plumas-Sierra Rural Electric Cooperative, the Truckee-Donner Public Utility District, the Bay Area Rapid Transit District (BART) and the Port of Oakland, is a member of the California joint powers agency known as Northern California Power Agency (NCPA). NCPA has a variety of jointly owned facilities, including:

• Geothermal Project--located in Sonoma and Lake Counties. • The Combustion Turbine Project Number One (CT 1)--five combustion turbine

units. Two are located in Roseville, two in Alameda and one in Lodi. • Hydroelectric Project Number One--three diversion dams, the Collierville

Powerhouse, the New Spicer Meadow Dam, and associated tunnels located in Alpine, Tuolumne and Calaveras counties.

• The Lodi Energy Center--a natural gas-fired, combined-cycle plant in Lodi.

9.3 M-S-R Public Power Agency.

The City, along with the Modesto Irrigation District (MID) and the City of Redding, is a member of the M-S-R Public Power Agency (M-S-R PPA). M-S-R PPA has interests in

• San Juan Generating Station. M-S-R PPA owns a 28.8% interest in the San Juan

Unit No. 4, a coal-fired steam generating unit in San Juan County, New Mexico. The ownership interest in this plant is to be terminated in December 2017.

• Big Horn Project. Two long term contracts for Big Horn 1 and Big Horn 2, both in Bickleton, Klickitat County, Washington.

9.4 M-S-R Energy Authority. This Gas Supply Agreement provides the supply at a discount below the monthly market index price over the 30-year term. 9.5 Seattle City Light-NCPA Exchange Agreement. NCPA, on behalf of Healdsburg, Palo Alto, Ukiah, Lodi and Roseville, negotiated a seasonal exchange agreement with Seattle City Light (SCL) for 60 MW of summer capacity and energy with a return of 46 MW winter capacity and energy. The service began in 1995 and will terminate in March 2018. 9.6 Western Area Power Administration Purchased Power. As a municipal utility, SVP is entitled to a portion of the power produced or purchased by the Western Area Power Administration (Western). The power marketed by Western to the City is provided on a take-or-pay basis where Western’s annual costs are allocated to preference customers based on their participation percentage. Western then allocates the annual take-or-pay charges to the preference customers based on a monthly percentage to reflect anticipated seasonal energy deliveries.

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9.7 Wholesale Power Trading and Market Energy Resources. As an active trading entity in California’s wholesale electric power markets, SVP gets a substantial portion of its energy needs from the market through short-term contracts varying from a day to a year or more. SVP’s market activities allow it to hedge against rapid or unpredictable fluctuations in energy market prices.

9.8 Interconnections and Transmission and Distribution Facilities. SVP’s service area is surrounded by PG&E. The two systems are interconnected at two City-owned 115 kV receiving stations – Northern Receiving Station (NRS) and Kifer Receiving Station (KRS). The City also has a 230 kV interconnection with PG&E at PG&E’s Los Esteros Substation (LES) in San Jose. Power received at LES is transmitted about six miles to NRS. 9.9 Transmission Rights Owned (through JPAs).

In addition to its generation resources and access to the wholesale power markets, SVP has rights to transmission services through its participation in the Transmission Agency of Northern California (TANC). SVP also possesses, through TANC, rights to transmission service between PG&E’s Midway substation and TANC’s members, known as the South of Tesla (SOT) Principles. SVP has a share in NCPA’s Geysers Transmission Project, from the Geysers to PG&E’s bulk transmission system. SVP also has rights to transmission on the Southwest Transmission Project (SWTP) from central Arizona to southern California through M-S-R PPA. The SWTP is currently out on a Request for Offers by M-S-R PPA and may be sold or leased in the upcoming year to two years.

NCPA is the schedule coordinator for most of the power that is transmitted to and from Santa Clara over the CAISO-controlled transmission grid. M-S-R PPA provides SVP with schedule coordination services for the San Juan Generating Station, the Big Horn projects and the SWTP. Western acts as schedule coordinator for SVP’s Hydroelectric Base Resource and Displacement programs, while Sacramento Municipal Utility District (SMUD) is the schedule coordinator for SVP’s use of the COTP. 9.10 California Independent System Operator (CAISO) Markets.

The CAISO operates a commodity exchange for electricity and capacity products. The markets (day ahead and real time) and their regulations have been designed to ensure that supplies are available and delivered to the correct locations for customer load. The day ahead (DA) market sets market-clearing prices and unit commitments, analyzes unit must-run needs and mitigates bids if necessary, which produces the least cost energy that can meet reliability needs. The market opens seven days before the trade date and closes the day prior to the trade date. The three day-ahead processes are market power mitigation determination, integrated forward market (IFM) and residual unit commitment (RUC).

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The real time (RT) market is a spot market to procure energy (including reserves) and manage congestion in the real time. Energy is produced to balance instantaneous demand, reduce supply if demand falls, offer A/S as needed and, if necessary, curtail demand. The market opens at 1:00 p.m. prior to the trading day and closes 75 minutes before the start of the trading hour. Generators are assigned in 15-minute intervals to be available to meet the difference between scheduled supply and demand. The process dispatches imbalance energy (the difference between what actually happens for each generator and load location and what they prearranged through schedules) and energy from A/S. It runs automatically and dispatches every 5 minutes.

Settlement processes for what the CAISO pays a Scheduling Coordinator (SC), such

as NCPA, or what the SC pays to the CAISO for energy and A/S are very complicated, with many different types of products, pricing and fines for failure to deliver. Generators can also be paid for delivering products and charged for failing to do so. Resources can provide energy, A/S or other products by making an economic bid or ‘self-scheduling.’ When a supply resource makes an economic bid, it puts in its bid for what it will sell its service for into the market. Supply bids are on a ‘bid curve’ from lowest price to highest. Demand bids in the price by the load center for what it is willing to pay are also on a ‘bid curve.’ The Market Clearing Price is where the bid price curve for supply and the demand curve meet. Supply at that price or lower is awarded the bid and paid the Market Clearing Price.

In general terms, for the DA market, the CAISO clears transactions in the IFM and

pays the SC for the MWh of energy delivered from generators, reliability demand response resources and other system resources at the price for that location (Locational Marginal Price [LMP] for that Pricing Node [PNode]). For each settlement period, the CAISO charges the SC for the MWh of demand multiplied by the LMP at that PNode. The CAISO also calculates and accounts for imbalance energy for each dispatch interval. It settles imbalance energy for each time interval for each resource within the CAISO Balancing Authority Area and all resources dispatched in RT.

10.0 ANCILLARY SERVICES AND OTHER RESOURCES FOR CAPACITY REQUIREMENTS

10.1 Ancillary Services

Electricity generation and consumption must balance on a moment to moment basis. Changes in consumption and disturbances at generation facilities impact the system balance and cause frequency deviations in the grid. Ancillary services (A/S) help to meet this ever changing need for supply. The requirements for A/S is different throughout the year, both by total volume required and what type is needed.

There are four types of A/S products: regulation up, regulation down, spinning

reserve and non-spinning reserve. Regulation energy is used to control system frequency. Frequency regulation is the second-by-second matching of generation to the load. Generators and other facilities providing regulation are certified by the CAISO and must

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respond to “automatic generation control” signals to increase or decrease levels of operation depending on the service being provided, regulation up or regulation down. Spinning reserve is unloaded capacity from generation already connected or synchronized to the grid that can deliver energy in 10 minutes. Non-spinning reserve is capacity that can be synchronized and ramping to a specified load within 10 minutes.

10.2 Resource Adequacy

Resource Adequacy (RA) is a requirement for LSEs, like utilities, to show that they can deliver the energy needed for customers, even if demand spikes. LSEs must demonstrate on monthly and annual time periods that they have purchased capacity commitments that are at least 115% of their peak loads, to ensure there will be enough commitments from real, physical resources to provide for demand variation and to ensure system reliability. RA is also an important source of revenue to generators.

The process to ensure appropriate RA continues to evolve. The CPUC and CAISO

have convened multiple workshops addressing a number of related issues. The stakeholders in this decision making process are grappling with whether RA should ultimately evolve into an East coast–style centralized capacity market or instead continue as a bilateral market between LSEs and their generators (either owned by the LSE or purchased through a contract). In addition to the high-level policy issues, the workshops have also looked at how to make sure there are adequate resources to serve all customer load in real time through Flexible Resource Adequacy (FRA) capacity.

The CAISO develops deliverability criteria for each LSE to meet and counting rules

for RA resources. The amount of RA that a unit provides to the system is based on its Net Qualifying Capacity (NQC), which is plant’s average rating on hot afternoon summer day—the system’s peak time. To get the NQC, plants are de-rated from their maximum production capability (Pmax) based on ability to produce at the system peak. Resources that are counted for RA purposes must be available to the CAISO for the capacity for which they were counted. If a resource is not available or adequately replaced at the appropriate geographic location with the appropriate type of RA, in situations such as when there is an unplanned outage, the LSE may have to pay significant fines to the CAISO.

10.2.1. Reliability Services Initiative (RSI)

As shown in the CEC graph below, increases in variable energy generation, particularly solar PV, on the grid will continue to impact peak requirements. When solar generation stops while peak loads continue to increase in the early evening, other flexible resources need to be available to provide both energy and A/S. The “Duck Chart” shows that the need for these variable resources will increase over time. To meet this need, the CAISO has imposed FRA requirements on utilities for assets with flexible operating capabilities that can quickly ramp up or down as customer needs vary by hour or time of day. FRA will be needed for the markets on a Day Ahead (DA), Fifteen Minute (FMM), and

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Real Time (RT) basis. Facilities are defined as having flexible capacity based on their speed to ramp up and down, time to start up, and abilities to cycle on and off frequently, sustain the ramp, change ramping directions and reduce output without emission limitations.

The Duck Chart--Net Supply/Demand on the California Grid in 2012-13, Forecast through 2020

Source: CAISO

A second chart from the CAISO3 in its “Flexible Ramping Produce Draft Final Proposal” (December 10, 2014), shows that there will be an increasing need for flexible resources in the future. This will particularly be the case in the early evening, when solar supplies reduce quickly, but customer demand for electricity is still at its peak or in the morning at about 8 a.m., as load decreases while solar generation is starting to peak. An increasing number of generation or ES facilities will need to be available to ramp quickly up and down to ensure sufficient supplies are available without voltage deviations.

3 Operating Flexibility Analysis for the CAISO; Mark Rothleder, Shucheng Liu, and Clyde Loutan, CPUC Workshop, June 4, 2012.

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Source: CAISO

Must Offer Obligations (MOO) occur when a resource is required to operate during certain parameters or situations. Payment for these resources is based on the market clearing price. The CAISO requires flexible capacity resources to submit economic bids into its market from 5:00 a.m. through 10:00 p.m. for all non-holiday weekdays. This set of hours gives the CAISO the ability to economically dispatch resources and meet ramping and contingency requirements at the least cost. For example, having enough economic bids in the market reduces the frequency with which the CAISO must curtail self-scheduled generation at the penalty price. The CAISO can to insert economic bids for resources that do not submit an economic bid on their own.

There are some exceptions in the must offer process for some generation types.

Hydroelectric resources, while capable of providing significant FRA, may not always be able to respond to CAISO dispatch due to environmental or water use restrictions. In addition, many thermal generators are constrained by operational characteristics, particularly if they have long start requirements or are use-limited. Long start resources cannot provide flexibility in the Real Time market, and use-limited resources frequently have controls on number of starts or the amount of run hours in a year.

Payments for Flexible Capacity under the proposed CAISO Resource Adequacy

Availability Incentive Mechanism (RAAIM) are planned to be based on a bid-based availability calculation and a comparison of the bids against a fixed allowed availability. Resources that perform under the availability threshold will be charged a penalty, and resources that perform over it will be paid an incentive payment. Both the penalty and incentive will be $3.79/kW month (or 60% of the CPM offer cap price). In addition, when RA capacity is unavailable due to some types of outages, the outage period will be removed from the calculation and not counted as available or unavailable.

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Much of Santa Clara and NCPA facilities, as load-following MSS LSEs, do not have to provide monthly or annual flexible capacity showings and will be exempt from the RAAIM for all capacity types—local, system and flexible. The CAISO’s proposal for this exemption was based on the idea that MSS load-following LSEs must manage all of their own variability, including wind and solar resources.

The CAISO wants to ensure MSS load-following LSE fully cover their share of

flexible capacity for variable resources and don’t lean on other LSEs for flexible capacity. If the portfolio includes variable energy resources, such as solar or wind, any increase or decrease from these resources must be balanced by another resource in the LSEs’ portfolio. If they are not in the portfolio, LSEs, such as SVP, must provide an additional MW of flexible capacity for each MW of capacity from variable energy resources that was supposed to be on in the MSS resource portfolio but was not.

Another requirement that the CAISO is proposing for MSS load-following LSEs is

that they will be required to show FRA for the lesser of 3.5% of expected peak load or the LSE’s contribution to the three hour net load ramp. This is to ensure that these LSEs can cover any potential overlap between flexible capacity resources and resources that are used to provide contingency reserves.

10.3 Load Following

When a utility can meet moment-to-moment changes in customer load demands with its own or contracted for generation, the utility is load following. Typically, load following utilities have large hydroelectric and/or natural gas powered turbines that allow rapid generation changes. This type of power is differentiated from base load generation (difficult and/or time consuming to start and stop, but produces steadily once in operation); peak generation (expensive and/or environmentally problematic to run, but can be used for periods of extreme need); or variable/intermittent generation (provides power when the sun shines, the wind blows or some other factor). As a load following utility, the CAISO requires SVP to keep its generation within a range called the deviation band. A deviation band is the range in which SVP can deviate its generation from load requirements without a penalty. 10.4 Phase-Shifting Transformer

A Phase-Shifting Transformer is a device for controlling the power flow through a transmission system. The basic function of a Phase-Shifting Transformer is to change the phase displacement between the input voltage and the output voltage of a transmission line, thus controlling the amount of active power that can flow in the line and enhancing the flexibility of the system. SVP is currently installing the State’s first phase-shifting transformer which allow electricity being brought into to the City to be changed from low voltage (115kV) to high voltage (230kV). This has the impact of reducing the cost from the CAISO’s TAC, which is priced at a higher rate for power coming in on the lower voltage

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lines. In addition, having this capability in Santa Clara will allow the CAISO to make operational changes, when necessary, to improve the reliability of electricity delivery throughout the entire South Base region. 11.0 SUMMARY

Silicon Valley Power maintains a diverse portfolio of resources to enhance reliability, environmental responsibility and price for its customers. When making resource acquisitions, SVP considers whether needs could be supplied through demand side opportunities, renewable energy or traditional generation sources. Carbon allowance pricing is added to the analysis for resources that emit GHG. This decision metric combined with its long-term history of concern for the environment and RPS requirements has led SVP to pursue a portfolio that has a broad array of resources, including high percentages of energy from carbon free and renewable facilities.

For this IERP, three future scenarios were modeled and analyzed: a baseline look

and two alternative scenarios—a low load/low hydro/low cost and a high load/high cost. A variety of factors can impact the overall planning process for the utility. Some of the most impactful items, including hydroelectric resource levels, natural gas prices and costs of carbon and transmission pricing, were included in the modeling. Other internal and external factors are also major aspects to cost effectively serve customers.

Under the most likely situations, large hydroelectric remains the most economical

major supply-side resource for a variety of ancillary services and flexible resource adequacy, but its usefulness as base load is limited by drought and uncertain availability during peak demand periods. Energy efficiency is a very cost-effective resource; however, long-term reliability and continuity of countable savings is doubtful as codes and standards upgrade. Natural gas resources remain the most reliable resource for energy and ancillary services. Periods of drought or major swings in natural gas prices (including carbon allowances) will impact the relative economics of these resources. During base and high load scenarios, there will be times in the winter when purchases will be required. If needed, adding wind generation from locations with capacity factors similar to Big Horn 2 is likely to fit the need most closely.

Assuming that the policy goals in California continue to support demand side

resources and carbon emission free generation, increased legislation should be expected to require the installation and operation of technologies. As load could be reducing due to DG and ES installation by customers, these new resources would strand some existing supply resources and make some current PPAs less cost-effective. Fixed costs would continue to increase while the load base would lessen, thus necessitating increasing rates. The higher priced utility service then would give economic justification for even more customers to install their own DG and ES, which would further increase the amount of stranded SVP assets and lead to lower load requirements over time. In order to ensure that it avoids this spiral and continues to meet customer needs in an economic manner,

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SVP should regularly (annually at a minimum) analyze its cost of production for all resources—demand and supply side. In addition, when making resource acquisition decisions, the full range of options should be reviewed including life cycle costs and customer rate impacts as a part of the analysis.

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APPENDIX A: SCENARIO ANALYSIS METHODOLOGY

The IERP modeling approach seeks to determine the comparative cost, risk and reliability attributes of resource portfolios. Three scenarios were defined in this review. In order to appraise electricity dispatch options and compare the cost of these scenarios, SVP ran variations on its PLEXOS system, which is an energy market modeling and forecast simulation software. The scenarios analyzed for this IERP include model runs of future resource mixes and costs to dispatch these resources under several different situations. Variables that are important in the pricing and availability of future supplies were included in developing the costs to dispatch resources in different load profiles (low, medium and high changes in demand). First, a base case was analyzed. After the initial review, sensitivity analyses were run on variations in hydroelectric supplies, natural gas prices, carbon allowance costs, customer demand, TAC rates and differing RPS requirements. Each of the resource plan scenarios was modeled for its impacts on SVP’s ability to deliver service to customers and at what expected price.

For supply resources and pricing, the comparative price to run resources was

based on average historical pricing and assumptions for future increases in major cost categories, the energy forward price curve for both electricity and natural gas, and the estimated production profile for generation types. Solar and wind resources, for example, had profiles that varied by month and time of day based on historical patterns. For the San Juan Generating Station Unit 4 coal plant, ownership interest is shown to end on December 31, 2017, following the term sheet developed by the facility’s owners.

Below is a more detailed description of the modeling process, the assumptions,

methodology and results of the scenario analyses. I. Key Assumptions:

No large changes in the overall legislative or regulatory climate, with the exception that increases in both the RPS and carbon allowances pricing are analyzed.

No significant break-through technologies are included in the analysis that would create unexpected changes in cost-effective supply or demand side resources.

Load remains dominated by industrial customers with high load factors and little seasonal peak.

No major generation resources suffer catastrophic failures.

Transmission remains an increasingly large percentage in the cost of delivering service for resources generated outside of the SVP MSS area.

II. Methodology:

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PLEXOS models run on the utility market and dispatch with load forecasts under low, average and high scenarios to determine energy needs.

Analyzed this load in situations where hydro had low and average water availability over the period.

Varied the cost of Transmission Access Charges, natural gas and carbon allowances from low to high.

Looked at scenarios under current and potentially increase RPS’s.

Summary of Variables and Scenarios Used in the Analysis Three scenarios were run—a base case, a low growth/price case with two periods of drought and a high growth/price case that assume average water conditions. A summary of the different variables for each scenario is shown below.

Variable Scenarios

Low Load/Costs Base Case High Load/Costs

Hydro

Low Water—2 droughts (2015- 2016 and again 2020-2021) during the period.

Average Water No droughts--Average water in every year

Natural Gas Low Price Curve Average Rate of Increase.

High Price Curve

Carbon Allowances



$35 per allowance.

Customer Demand (Load)

Drops by 10%--remains lower than historical.

Average—follows historical trends.

High—starts higher than average due to business growth.

Transmission Access Charge



Higher due to more wires and more costly construction.

Renewable Portfolio Standard



Increases to 50% RPS by 2030. Interim requirements increase.

SCENARIO DETAILS

Base Case

Load forecasts are based on actual usage in 2013 with adjustments based on known customer changes during 2014. After that, both total load (MWh) consumed and

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peak demand (MW) are assumed to increase at 1% per year. Inflation rates are expected to go up slowly from 1.6% in FY 2015 to 3.1% in 2020 and then leveling off at 2.5% for the future. Carbon allowance prices continue on their current trajectory, starting at $11.43 in 2014 and increasing at 5% per year plus CPI. TAC and natural gases increase slowly based on current forecasts. Hydroelectric generation capacity remains average throughout the period. There are no legislated changes to the RPS during the period.

Source: PLEXOS runs; November and December 2014

Monthly usage continue to be relatively flat, with only slight variations each

month. The maximum load requirement increases very slightly in summer months, but there is no extreme peak in summer demand as is the case with many California utilities. This relatively flat load profile is due to SVP’s customer mixture, where a majority of sales come from industrial companies that operate all day, every day year around. In addition, Santa Clara’s temperate weather results in a fairly low need for air conditioning and other peak usage demands.

Source: PLEXOS Baseline run; November 24, 2014

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Under normal operating conditions, there will be period of time when electricity will need to be purchased and others when sales to the market will be required. In general, natural gas resources will continue to be the most favorable for sale—either the fuel itself or, less commonly, the electricity generated from it. Sales are mostly likely expected during normal hydroelectric years during run-off, when hydroelectric resources peak. This early summer effect can be more clearly seen in a graph of one year, 2019 is chosen to exemplify the issue. At those times, the market will likely have sufficient electricity available, and it is most likely that natural gas will be sold into the market.


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Another cost factor on generation is the TAC to get energy into Santa Clara. This additional fee is added to the price of electricity generated outside of Santa Clara, so it does not apply to DVR, CoGen or the local solar facilities. As shown below, the High Voltage portion of the TAC charge on its own is expected to increase from around $10 per MWh in 2015 to somewhere between $20 and $40 per MWh in 2024, depending on the amount of cost overrun that approved and likely projects achieve—continuing an ongoing trend that exceeds the rate of CIP growth.

Source: Navigant Consulting/TANC; January 2015

Low Load/Costs

Load forecasts in the low load/low costs scenario are based on actual usage in 2013 with reductions of 10% over the period. Inflation rates increase at the same rate as for the base case. Carbon allowance prices continue on their current trajectory, starting at $11.43 and increasing at a rate of 5% per year plus the consumer price index. TAC and natural gas are presumed to increase slowly. Hydroelectric generation capacity is lower, with two droughts in the period. There are no legislated changes to the RPS. With low load, current resources often provide more electricity than required.

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Source: PLEXOS Modeling; Low Load/Cost Scenario; December 2014

As can be seen on the charts below, SVP needs to sell resources during most of

the summer and buy from the market in the winter. This situation is more severe during a drought. This situation would become more acute if distributed generation grows significantly as a portion of the load, as solar PV, the primary source of DG, produces more in the summer and less in the summer—leading to more periods of over generation. While ES could relieve some of the over generation issues by shifting the time period when the electricity is available, this technology does come at a cost.


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High Load/Costs

Load forecasts are based on actual usage in 2013 with adjustments from known customer changes during 2014 and certain block loads added on top of the base case. Inflation rates are expected to increase at the same pace as the base case. Carbon prices increase to $35 per allowance due to insufficient supply and increasing demand. TAC and natural gas costs increase at higher than expected rates. TAC increase will be due to more and more construction of lines to meet the need for more renewable generation at increasingly remote locations. This construction cost continues to exceed original estimates by about 100%. Natural gas prices increase at higher rates as the need for flexible generation sources becomes more acute due to greater levels of variable renewable generation in the system. Hydroelectric generation capacity is assumed to be average. The RPS is legislated to increase to 50% by 2030, so generation from these resource types are likely to be added to the portfolio during or right after the study period to reach mandated levels. In looking at the monthly scenario below, the most logical resource to add in such a situation would be wind from some locations, as it can generates during the time when load is projected to be greater than supply resources.

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Source: PLEXOS Modeling; December 2014

Purchasing wind generated power from resources in some locations such as Big Horn 2, could meet this need for winter energy. As shown below, Big Horn 2 produces the most energy in the November through March period. On the other hand, Big Horn 1 has a more even capacity factor, so more generation from this or similar facility would likely lead to needing to sell other resources during the late spring/early summer runoff period.

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COMPARISON OF SUPPLY COSTS

Base Case

In the table below, the total costs and capacity of each resource type from the base case scenario is shown for comparison purposes. Costs are based on SVP’s average generation costs in the FY 2014 budget. Facilities used in the comparison include current plants and their ownership/PPA capacity with contracted and/or forecasted pricing changes through 2024. As can be seen, on a per MWh basis, geothermal has the lowest cost, with landfill gas and solar PV being the most expensive resources (in current contracts; future contracts for solar PV are likely to be less costly). Large hydroelectric is shown to decrease early in the period, presuming regular water years return after 2016.

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Small hydro generation slowly increases over the period from a price near that of geothermal to one just below projected price of natural gas generation without the cost of carbon allowances added into the per MWH cost. This increase in small hydro pricing is due to new higher-priced contracts for generation from smaller dams that come on line in the period.

Source: PLEXOS Baseline Run; November 24, 2014

When the projected emissions allowances are added to the mixture, natural gas

becomes more expensive than both small hydroelectric and wind over the period. Coal remains more expensive than large hydroelectric until it is phased out in December 2017 (mid-year Fiscal Year 2018), but the divergence between the two commodities is more dramatic with the carbon allowances. There are no other differences in relative power cost rankings, as shown below.

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The greatest source for electricity generation by source and by month over the year (2015) is typically dominated by natural gas facilities, except in the spring when annual repair shut downs are scheduled. Hydro and wind production peak in the late spring and early summer, with solar, landfill and small hydro facilities providing small percentages of supply resources in the portfolio throughout the year. Hydro is lower in the summer in 2015, as the state has been in a severe drought for several years, and production is not up to normal expectations. As shown below, this pattern changes somewhat over the study period, as large hydro is projected to become a great portion of the generation portfolio, while the eligible renewable resources slightly increase to meet the increased RPS requirement.


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Potential Changes to the Base Case

After the base scenario was run and scrutinized, further analysis comparing the portfolio with the cost to dispatch differing amounts and types of demand side resources was completed. A summary of this comparison is discussed below.

Increase Energy Efficiency

In the past six years, EE programs have provided lifetime savings at a cost comparable to a supply resource (between $25 and $60 per MWh). These programs have been successful at a significant benefit to cost level, with ratios between 2.4 and 5.6 since 2008 (where a number great than 1 is a beneficial program). However, each year’s programs have typically provided 1% or less savings on an annual basis compared to usage. The percentage of savings compared to sales has dropped annually since FY 2009. This is likely due to the fact that while customers and the utility continue to gain benefits from implementing EE equipment and processes, the utility can only count EE savings in its programs if these installations or changes in behavior are not required under current codes and standards. Regular updating and improving of codes and standards have made it more difficult over time for SVP to count EE upgrade savings in its programs.

Assuming that the average equipment replacement or building upgrade has an

average 10 to 15 year life, current and historical EE programs have a cumulative reduction on total load in Santa Clara of about 10% per year. When SVP procures more resources, the potential to increase EE programs should be included in the review.

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Source: SVP Public Benefit Annual Reports and Utility Fact Sheets

Assuming EE costs per MWh of reduction continue in the range they have been in the past five to six years, it remains quite cost-competitive with other resource prices, particularly solar, wind and natural gas. Additional carefully constructed and cost-effective EE programs have the potential to be implemented at a price that is in the range of natural gas or small hydro resources and significantly less than landfill gas, wind or solar PV. However, such savings are likely not sustainable over a long term, as there is a good possibility that codes and standards will continue to increase and thus erode the potential for utility programs to count, report and verify savings.

Source: SVP PLEXOS runs; December 2014

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Add Energy Storage

As ES becomes more commercially available, costs are projected to fall. In addition, utilities and vendors will gain more field experience with a variety of technologies, which will allow SVP to confidently compare it with other resource options. ES can be added to the portfolio in those areas where it makes operational and economic sense for the utility and its customers. These comparisons should be made at the time of future procurement decision, as the economics on ES are likely to change dramatically over the 10 year period in the IERP. Some industry experts estimate that ES will be competitive with peak power plants by 20184. It should be noted that while ES can move electricity supplies through time, there is a total energy loss through this process, and energy will still need to be generated by some resource. Thus, pricing for ES should be compared fully on a life cycle basis with other energy and capacity, which means that in some cases storage will be an additional cost over and above that of the generation source. Note in the US Energy Information Administration (USEIA) 2013 comparison5 of the capital costs to develop and build new plants shown below, a 150 MW solar PV plant will cost on a nationwide average $3,873 per kW. That same PV generation facility with only 20% of the capacity covered by storage, is $4,235 per kW—an increase of about 9%.

Source: USEIA; April 2013 Includes 30% investment tax credit for PV and solar thermal. Wind, geothermal, biomass, hydro and landfill gas have differing per $/MWh subsidies

4Robert Walton, November 13, 2014 http://www.utilitydive.com/news/study-energy-storage-will-soon-replace-peaker-plants/332588/ 5 US Energy Information Administration; Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants; April 2013

http://www.utilitydive.com/news/study-energy-storage-will-soon-replace-peaker-plants/332588/

http://www.utilitydive.com/news/study-energy-storage-will-soon-replace-peaker-plants/332588/

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Capital costs to develop and construct a generating facility vary dramatically on a per kW basis, as shown above, ranging from less than $700 per kW for conventional combustion natural gas turbine plants to over $5,000 per kW for onshore wind. It is vital, however, to compare full lifecycle costs of generation types when developing a resource portfolio. As can be seen on the two graphs below, which include data from the USEIA collected in 2013, onshore wind and solar PV systems are comparatively expensive to construct, but do have relatively low fixed costs and no variable operating expenses. ES adds very little ongoing operation and maintenance (O&M) expense to the solar PV system, so additional capital of the ES should be included with O&M in the total lifecycle capital analysis.

Source: USEIA; April 2013. Additional Location Based Cost Increases: Sacramento 8.40%, San Francisco 16.80%

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Source: USEIA; April 2013. Additional Location-Based Cost Increases: Sacramento 8.40%, San Francisco 16.80%

Low Load/Costs

In a scenario that assumes low costs for natural gas and emissions, as well as a reduced hydroelectric availability and 10% less customer load than is currently the case, natural gas remains the most significant supply resource over the planning horizon. With two droughts during the period, less carbon free hydro resources will be available to deliver flexibility to the electric system to adapt between customer load patterns and availability of renewable resources (as shown in the duck chart above) in carbon free manner. Without legislation to require additional renewable or demand side resources in the portfolio, the economic decision would be to generate from natural gas sources as much as possible. This scenario would provide neither customers nor SVP with market signals to add ES, distributed generation or EE.

Assuming that the policy goals in California continue to support these alternative

resources and carbon emission free generation, without the economic justification to install these measures, increasing amounts of legislation could be expected to require the installation and operation of these costlier environmentally preferred resources. As these required additional resources would be serving a lower load than today, they would end up stranding some existing supply resources and make some current PPAs less cost-effective. The fixed costs in SVP’s system would thus continue to increase while the load base would lessen, thus necessitating increasing rates. The higher priced utility service then would give economic justification for more customers to install their own distributed generation and ES, which would further increase the amount of stranded SVP assets and lead to lower load requirements over time.

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Source: Low Load/Cost PLEXOS runs; December 2014


This scenario shows that until 2018, when the San Juan plant’s ownership is

terminated, there is more than sufficient generation capacity at SVP. During the first modeled drought period of 2015-2016, hydroelectric resources are not as available, so natural gas resources are used. Assuming gas prices are low and there is no drought (2017), gas resources can be sold into the market, as hydro is available. Once the San Juan ownership ends in 2018, there will be less available to cover load or to sell. Periods of time when generation exceeds load are in the winter months, when market prices are likely to be lower. Should additional resources be needed to fill the gap, wind generation is likely to be the best fit.

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High Load/Costs

Under this scenario, hydroelectric resources remain at an average level during the period, while natural gas and carbon costs escalate and load increases. One of the major changes to the supply forecast is that natural gas becomes more expensive than hydroelectric and wind resources under current contract or ownership and approaches the prices of landfill gas generation. Large hydroelectric is available and used more in the late spring. As natural gas generation pricing increases, and presuming that the cost of energy storage and new contracts for renewables, such as solar and wind, reduce in price over time, there will be an increasingly greater incentive for SVP to procure ES or new renewable contracts to offset higher priced natural gas to meet increased load.

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Low Load/Cost Scenario

Load 2,875.39 2,904.14 2,933.18 2,962.51 2,992.14 3,022.06 3,052.28 3,082.80 3,113.63 3,144.77

Total Generation 3,086.94 3,053.83 3,557.41 3,494.09 3,265.61 2,882.42 2,894.03 3,283.91 3,306.68 3,319.38

System Cost ($000) 133,799.56$ 138,409.05$ 165,009.86$ 167,817.67$ 165,130.09$ 153,047.56$ 157,442.93$ 178,382.82$ 182,496.07$ 185,957.22$

Avg system Cost ($/MWh) 43.34$ 45.32$ 46.38$ 48.03$ 50.57$ 53.10$ 54.40$ 54.32$ 55.19$ 56.02$

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Source: High Load/Cost PLEXOS runs; December 2014

Because of the increasing price of natural gas and reduced prices for ES or

renewable supply in this scenario, distributed generation would also become more economically attractive for customers. This would have the result of decreasing load requirements for SVP. With current supplies either owned or in long-term PPAs, the result could be stranded relatively higher priced assets being included in SVP’s rate base, with less load over which to spread fixed costs. Rate increases for the remaining customers would further enhance the benefit to customers who installed distributed generation. The high load/high cost scenario is not sustainable. Costs could remain high and load would continue to decrease, resulting in a negative revenue spiral for SVP.

Source: High Cost/Load PLEXOS runs; December 2014

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In the high load/high cost scenario, there will be less generation available to sell into the market once the San Juan ownership is terminated. The need to procure more resources through PPAs, ownership models or on the market will grow over time. If load and natural gas prices remain high, as in this scenario, there will be an economic potential for SVP to pursue ES or additional renewable energy options. However, if the negative spiral above regarding potential increased rates and other concerns does occur, there would be no need to make such purchases without stranding other assets.

Source: High Cost/Load PLEXOS runs; December 2014

High Load/Cost Scenario 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024

Load 3,336.78 3,368.99 3,402.68 3,436.71 3,471.07 3,505.78 3,540.84 3,576.25 3,612.01 3,648.13

Total Generation 2,927.47 3,524.73 3,604.10 3,524.21 3,268.15 3,280.17 3,275.78 3,276.51 3,276.19 3,258.21

System Cost ($000) 150,642$ 174,927$ 184,958$ 186,906$ 182,563$ 188,695$ 192,225$ 194,584$ 196,723$ 197,172$

Avg system Cost ($/MWh) 51.46$ 49.63$ 51.32$ 53.03$ 55.86$ 57.53$ 58.68$ 59.39$ 60.05$ 60.52$

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APPENDIX B: SILICON VALLEY POWER SUPPLY RESOURCES

SANTA CLARA OWNED RESOURCES

Cogeneration.

The City owns and operates a cogeneration plant which began operation in 1981. It provides steam for sale to a paperboard plant in the City and delivers power to the City’s electric distribution system. The City upgraded this plant to obtain a new name-plate rating of 7.4 MW of capacity in July 1995. Fuel for the plant (natural gas) is generally purchased through fixed price term contracts. Stony Creek Hydroelectric System.

SVP owns and operates three hydroelectric plants consisting of (i) a 4.9 MW hydroelectric generator at the U.S. Bureau of Reclamation Stony Gorge Dam near Willows, California, which was completed in 1985, (ii) a 6.2 MW hydroelectric generating plant at the U.S. Army Corps of Engineers’ Black Butte Dam near Orland, California, which was completed in late 1988, and (iii) a 0.53 MW hydroelectric generating plant located at the Orland Unit Water Users’ Association High Line Canal/South Side Canal drop near the Black Butte dam, which was completed in late 1988. These facilities deliver power based on water availability (run of river).

Gianera Generating Station.

The City owns and operates a nominal 49.9 MW dual fuel (natural gas and fuel-oil) combustion turbine generating plant consisting of two 25 MW units, which were completed in 1986 and 1987, respectively. This generator helps meet the City’s peak load and Resource Adequacy requirements. PG&E Grizzly Project.

Under a 1990 settlement agreement with PG&E, SVP agreed to finance and own 100% of a 20 MW hydroelectric facility (the Grizzly Project) located on Grizzly Creek above the North Fork of the Feather River in Plumas County, California. The Grizzly Project operates in combination with PG&E’s Bucks Creek hydro project. Santa Clara is a joint licensee in PG&E’s Bucks Creek project. PG&E constructed and operates the Grizzly Project, which was placed into operation in November 1993. Annual energy generation of the Grizzly Project is estimated at 57.3 GWh in an average water year and 26.1 GWh in dry years. This plant provides capacity and A/S (spinning and non-spinning reserves). Donald R. Von Raesfeld Power Plant.

The City constructed and placed into commercial operation on March 22, 2005, a 122 MW nominal/147 MW peak, natural gas-fired, combined cycle power plant known as

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the Don Von Raesfeld Power Plant (DVR). DVR is located in an industrial area of the City, on the site of SVP’s Kifer Receiving Station. DVR includes its own switchyard and connects to an existing 115 kV transmission line that currently crosses the plant site. Natural gas for the plant is delivered through an approximately two mile gas pipeline from the local transmission main of PG&E. The City has long-term agreements with Shell Energy North America and M-S-R EA in place for a significant portion of fuel requirements and actively manages the quantity and price risks associated with fuel supply quantities not in long-term agreement. Fully base loaded, the Plant could generate about 1,000 GWh per year. The plant provides capacity, Resource Adequacy and A/S for SVP.

Jenny Strand Solar PV System.

SVP owns a 100 kW solar electric facility in Santa Clara on the Jenny Strand Park. It was constructed in 2012.

Tasman Parking Structure Solar PV System.

This solar electric project was constructed in 2013 on one of the City’s parking structures. It produces up to 400 kW of power. JOINTLY OWNED RESOURCES

NCPA Geothermal Project.

SVP has 65% and 34.13% entitlement shares in the capacity of NCPA’s Geothermal Project Plants 1 and 2. In 2013, Santa Clara received 363.9 GWh of electric energy from the Geothermal Project. SVP’s share of the current CAISO maximum rated capacity of the project is 71.7 MW. SVP has a 55 MW share in NCPA’s Geysers Transmission Project, which provides a link from the Geysers to PG&E’s bulk transmission system. This facility provides capacity, Resource Adequacy, A/S and Renewable Energy Credits (RECs) toward the Renewable Portfolio Standard (RPS).

NCPA Combustion Turbine Project No. 1.

SVP has a 25% entitlement share in NCPA’s Combustion Turbine Project No. 1. SVP’s share comes from two Alameda plants and one Lodi plant. SVP uses this entitlement for Resource Adequacy and to meet peak load requirements. For 2013, SVP received 255 MWh of energy from the Combustion Turbine Project No. 1.

NCPA Hydroelectric Project.

SVP has purchased from NCPA a 37.02% entitlement share in NCPA’s Hydroelectric Project, including Collierville and New Spicer dams (a 1.16% entitlement share was laid off to Santa Clara from the cities of Biggs and Gridley). SVP is using this project to serve peak load and to provide capacity to support non-firm purchases of energy at market

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prices. For 2013, SVP received 98.2 GWh of electric energy from the NCPA Hydroelectric Project. Santa Clara receives this entitlement by using transmission service available under its MSS with the CAISO. The facilities provide capacity and Resource Adequacy. Collierville also delivers A/S, while New Spicer provides RECs.

NCPA Lodi Energy Center Project.

SVP has purchased from NCPA a 25.75% share (72 MW) in the Lodi Energy Center (LEC) Project. The LEC was placed into operation in 2012. For 2013, SVP received 311.8 GWh of electric energy from the LEC. LEC provides capacity, Resource Adequacy and A/S.

TANC California–Oregon Transmission Project.

Santa Clara is a member of the Transmission Agency of Northern California (TANC). SVP was entitled to 20.4745% of TANC’s share of COTP transfer capability (approximately 278 MW net) on an unconditional take-or-pay basis. On July 1, 2014 Santa Clara laid-off 147 MWs of this entitlement to other TANC members under a 25 year agreement. SVP uses a portion of its share of the project transfer capability of the COTP to provide transmission from the Big Horn Projects and Santa Clara’s share of an exchange agreement between SCL and NCPA.

TANC Tesla–Midway Transmission Service.

TANC has arranged for PG&E to provide TANC and its members with 300 MW of firm bi-directional capacity on its transmission system between its Midway Substation near Buttonwillow, California, and its Tesla Substation near Tracy, which is near the southern end of the COTP. SVP’s share of Tesla–Midway Transmission is 81 MW. M-S-R PPA – San Juan.

Santa Clara, along with the Modesto Irrigation District (MID) and the City of Redding (Redding), is a member of a California joint powers agency known as the M-S-R Public Power Agency (M-S-R PPA). M-S-R PPA owns a 28.8% (approximately 146 MW) interest in the San Juan Unit No. 4. The San Juan Unit No. 4 is a coal-fired steam electric generating unit with a net generating capability of 507 MW, located in San Juan County, New Mexico, which was constructed and is operated by Public Service Company of New Mexico (PNM). Unit No. 4 is one of four generating units that together make up the San Juan Generating Station. The ownership interest in this facility is expected to end December 31, 2017. SVP uses its portion of San Juan Unit 4 to serve in its own system or for short-term layoffs to others based upon monthly economic dispatch considerations. M-S-R PPA has firm transmission rights to transmit the capacity and energy through agreements with Los Angeles Department of Water and Power (LADWP) and through the Southwest Transmission Project. San Juan provides capacity and Resource Adequacy.

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M-S-R PPA Southwest Transmission Project.

The Southwest Transmission Project (SWTP) consists of an interest in a 500 kV alternating current transmission project between the central Arizona area and the Los Angeles basin to provide for the delivery of power and energy from San Juan Unit No. 4. Transmission service from the Midway Substation to Santa Clara’s electric system is provided by the TANC Tesla–Midway Service. Beginning in early 2014, Santa Clara has ended its firm transmission service agreement with SCE, after an economic analysis found that Santa Clara could access the CAISO’s new firm use transmission and bring the San Juan power home more economically. M-S-R PPA is exploring layoff or sale options with regards to its ownership entitlement to 72 MWs of capacity in the Mead – Phoenix, Mead – Adelanto transmission line.

M-S-R PPA Purchased Power–Big Horn Projects.

In 2005, M-S-R PPA entered into power purchase agreements with Iberdrola Renewables, Inc. (formerly PPM Energy, Inc.). SVP receives 52.5% of the power purchased by M-S-R PPA from Big Horn I, which is about a 105 MW share of the output. Power deliveries commenced on October 1, 2006 and will continue through September 30, 2026. For 2013, SVP received 250.5 GWh of energy from the Big Horn I Project and uses a portion of its transfer capability of the COTP to provide for transmission from the California-Oregon border. M-S-R subsequently negotiated a 25-year agreement with Iberdrola for the purchase of the output from a 50 MW expansion of the Big Horn I Project, the Big Horn II Project. The Big Horn II Project commenced operations on November 1, 2010. SVP receives 35% of the output from this project, or about 17.5 MW of project capacity. For 2013, SVP received 43 GWh of energy from the Big Horn II Project. Both Big Horn projects deliver RECs for SVP.

M-S-R Energy Authority – Gas Prepay.

Santa Clara, along with MID and Redding, have also formed a California joint powers agency known as M-S-R Energy Authority (M-S-R EA). In 2009, Santa Clara participated in the M-S-R EA Gas Prepay Project, which provides for a secure and long-term supply of natural gas of 7,500 MMBtu daily (or 2,730,500 MMBtu annually) through December 31, 2012, and 12,500 MMBtu daily (or 4,562,500 MMBtu annually) thereafter until September 30, 2039. The Gas Supply Agreement provides this supply at a discounted price below the monthly market index price. PURCHASED POWER AGREEMENTS

Altamont Wind Power Project

In 2006, the City and AES Seawest Inc. entered into five-year land lease and power purchase agreements, allowing Seawest to rent 691 acres in the Altamont area of Alameda County from the City and sell wind power generated on the rented land to the

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City. This project (now with Ogin or Zonn) adds about 1 percent of eligible renewable energy to the City’s annual power mix and RECs. The wind plant achieved commercial operation on May 3, 2007. The facility includes 200 small wind turbines, with a capacity of about 100 kW each. The City acts as the Scheduling Coordinator for the facility and schedules the output from the facility into the ISO Participating Intermittent Resource Program, and the resulting energy is then traded to the NCPA Scheduling Coordinator portfolio which serves the City’s load. The PPAs were scheduled to terminate in 2011. SVP is currently negotiating arrangements to lease the land and repower the facility with other vendors.

Ameresco Landfill Gas Facilities.

SVP has Purchased Power Agreements (PPAs) with Ameresco for three landfill gas facilities, one in town with the other two in Manteca and Livermore. The out of town PPA’s give 100% of the output to SVP, were constructed on 2012 and provide a maximum of 4.6 MW in electricity. The in-town facility was completed in 2009 and provides 0.75 MW of power. All three facilities provide RECs.

Friant Small Hydroelectric Projects 1 & 2.

These small hydroelectric facilities in Fresno County are scheduled to go on-line in 2015 and 2016. They are expected to produce 25 MW and 7 MW of power, respectively. They will provide RECs for SVP.

G2 Landfill Gas.

Under a PPA signed with G2Energy in 2009, SVP receives up to 1.3 MW of landfill gas generated electricity with RECs from a facility in Wheatland, California.

Manzana Wind Facility.

In 2012, SVP participated in a PPA with Iberdrola for up to 50MW of energy and related RECs from a wind facility in Kern, County, California.

Seattle City Light-NCPA Exchange Agreement.

NCPA, on behalf of Healdsburg, Palo Alto, Ukiah, Lodi and Roseville, negotiated a seasonal exchange agreement with Seattle City Light (SCL) for 60 MW of summer capacity and energy and a return of 46 MW of capacity and energy in the winter. Deliveries under the agreement began June 1, 1995 and will terminate in March 2018. In May 2008, Healdsburg, Palo Alto and Roseville assigned their participation percentages to SVP, which resulted in SVP receiving 32.6 MW from SCL during the months of June through October each year, and SVP to provide 25 MW to SCL from December through mid-April each year.

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Tri-Dam Large and Small Hydroelectric Project.

SVP signed PPAs with The Tri-Dam Project to receive electricity generated from hydroelectric facilities in Tuolumne County, California. The facilities produce up to 109.5 MW (beginning in 2014) and 16.2 MW (2016) in normal water years and provide energy and Resource Adequacy. Three of the dams (the smaller ones) will also provide RECs.

Utility Scale Solar Electric Project.

Under a PPA with Recurrent Energy, SVP has, since 2013, received up to 20MW of energy with related RECs from a solar electric facility in Kern County.

Western Area Power Administration.

SVP is entitled to a portion of the power produced or purchased by Western as a preference power customer. In December 2000, SVP signed a 20-year agreement for the purchase of low-cost hydroelectricity generated power from the Central Valley Power (CVP) project. The CVP is a series of federal hydroelectric facilities in Northern California operated by the Bureau of Reclamation. The power is provided on a take-or-pay basis, and SVP pays 9.06592% of Western’s annual costs in exchange.

Wholesale Power Trading and Market Energy Resources.

SVP uses its energy, Resource Adequacy and transmission resources to buy and sell actively in five established wholesale power trading market zones: Mid-Columbia (MID-C), California-Oregon Border (COB), North of Path 15 (NP15), South of Path 15 (SP15) and Palo Verde Hub (PV). Trades may be directly with counterparties or through clearinghouses, such as the InterContinental Exchange (ICE).

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APPENDIX C: RESOURCE ADEQUACY PLAN

RESOURCE ADEQUACY PLAN DEVELOPMENT AND IMPLEMENTATION

The City, at its sole discretion and until notice to the contrary, and to implement this IERP, adopts the following procedures for developing RA Plans. Definitions for Resource Adequacy Plans

Capitalized terms not otherwise defined in this IERP shall be defined as set forth in the Master Definitions Supplement of the CAISO Conformed Simplified and Reorganized Tariff, including modifications proposed by the CAISO or FERC. Annual Resource Adequacy Plans

SVP provides an annual RA Resource Plan to the CAISO, either directly or through NCPA as SVP’s Scheduling Coordinator (SC), on a schedule and in the format approved by the ROC. The annual RA Plan includes SVP’s Demand Forecasts for each month of the year and identifies the RA Qualifying Capacity that SVP will rely upon to satisfy one hundred percent (100%) of each monthly Demand Forecast plus the monthly Planning Reserve Margin for the relevant reporting year. Monthly Resource Adequacy Plans

SVP will provide a monthly RA Plan to the CAISO, either directly or through NCPA as SVP’s SC, by the last business day of the second month prior to the compliance month and in the form approved by the ROC. The monthly RA Plan shall include the SVP monthly Demand Forecast; and shall identify the RA Qualifying Capacity that SVP will rely upon to satisfy the monthly Demand Forecast, plus the monthly Planning Reserve Margin for the relevant reporting month. Supply Plans

SVP will provide an annual Supply Plan to the CAISO, either directly or through NCPA as SVP’s SC, on a schedule and in the format approved by the ROC. SVP will provide a monthly Supply Plan to the CAISO, either directly or through NCPA as SVP’s SC, by the last business day of the second month prior to the compliance month and in the form approved by the ROC. Both the annual and monthly Supply Plans shall include a listing of SVP’s commitments to provide RA Qualifying Capacity for the applicable reporting period. Resource Adequacy Plan Confirmation

Once the CAISO has received each annual or monthly RA Plan provided by SVP or by NCPA on behalf of SVP, the CAISO’s proposed tariff provides for the CAISO to confirm that SVP has procured or owns sufficient Net Qualifying Capacity to comply with the

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Planning Reserve Margin. To the extent the annual or monthly RA Plan is alleged by the CAISO to not include sufficient Net Qualifying Capacity to satisfy the Planning Reserve Margin or in the case of a discrepancy alleged by the CAISO between information included in the annual or monthly Resource Adequacy Plan and a Supply Plan submitted by the Scheduling Coordinator of a resource identified in the annual or monthly RA Plan, SVP and/or NCPA will attempt to resolve the issue after such notification by the CAISO.

If SVP is informed of an alleged deficiency, and if SVP confirms that SVP’s annual or monthly RA Plan is deficient, SVP shall determine how the alleged deficiency will be resolved. If the CAISO alleges a mismatch between information included in the annual or monthly RA Plan and a Supply Plan submitted by the Scheduling Coordinator of a resource identified in the annual or monthly RA Plan, and the alleged mismatch is not resolved within ten (10) days prior to the first day of the compliance month, SVP understands that the CAISO will accept the value contained in the resource Supply Plan to set the Net Qualifying Capacity value for the applicable reporting month.

To the extent that SVP has not resolved a deficiency alleged by the CAISO in the annual or monthly Resource Plans within ten (10) days prior to the first day of the compliance month, the ROC shall explain, by the tenth (10th) day of the compliance month, to City Council why the identified deficiency has not been resolved, and inform City Council of the possible penalties or other sanctions to which SVP may be subject as a result of such alleged deficiency. SVP, either directly or through NCPA as its SC, shall report to the CAISO within thirty (30) days of any action taken by SVP in response to a deficiency notification other than a Supply Plan mismatch. Demand Forecasts

The monthly Demand Forecast included in the annual and monthly RA Plan shall be based on the monthly peak Demand responsibility of SVP that is consistent with the forecasts provided to the CAISO under Section 6.1 of the MSS. In addition to the monthly peak Demand responsibility of SVP, SVP shall also plan to meet any (a) firm Exports (including any operating reserve requirements placed on Exports), (b) SVP firm sales to third parties within the CAISO control area, and (c) on-demand obligations to third parties, as measured in megawatts. For the purposes of this Section, SVP’s peak Demand responsibility shall be equal to the SVP non-coincident peak Demand Forecast for the relevant month (irrespective of the CAISO system coincident peak). Planning Reserve Margins

The annual and monthly RA Plan will include a Planning Reserve Margin equal to no less than fifteen percent (15%) of SVP’s monthly peak Demand responsibility.

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Dispatching of SVP Resources by CAISO

The CAISO’s authority to Dispatch any portion of the capacity of any Generating Unit of SVP, other than in accordance with a bid submitted to the CAISO by SVP’s Scheduling Coordinator, shall be solely as set forth in and subject to Section 7.1 and Schedule 11 of the MSS. SVP’s RA resources and other generating resources are not subject to the CAISO’s must-offer requirements.

Resource Adequacy Qualified Capacity RA Qualifying Capacity shall be the quantity of capacity from a resource stated in

megawatts which is listed in the annual and/or the monthly RA Plan. The criteria for determining the types of resources that may be eligible to provide Qualifying Capacity and for calculating Qualifying Capacity from eligible resource types are stated in this IERP.

Local Resource Capacity

The CAISO is under a statutory obligation to ensure efficient use and reliable operation of the transmission grid consistent with mandatory NERC Planning Standards. In compliance with the NERC Planning Standards, the CAISO provides the electric system in its Control area with the ability to withstand sudden disturbances or unanticipated loss of system elements. There are portions of the CAISO electric grid that are considered ‘load pockets’ that are in greater need of reserve capacity than other portions of the electric grid. SVP and its electric utility customers benefit from the reliability of the electric grid provided by the CAISO’s compliance with NERC Planning Standards.

SVP has determined its responsibility to provide reserve Local Capacity to the

CAISO electric system using the following information:

(a) SVP’s forecasted peak load coincident with the CAISO peak load;

(b) The peak load forecast in the Pacific Gas and Electric Company (PG&E) Transmission Access Charge (TAC) area;

(c) Information provided by the CAISO in its “2015 LOCAL CAPACITY TECHNICAL ANALYSIS Final Report”

The following formula is then used by SVP to determine its responsibility to provide Local Capacity Requirements (LCR) to the CAISO grid and should have a close correlation with the results determined by the CAISO. However, if the CAISO LCR for SVP is greater than SVP’s determined LCR, SVP will commit to using the results provided by the CAISO. SVP may then choose to resolve the differences, if they are deemed significant. At the current time, SVP has much more local capacity than needed to meet its Local Capacity requirements.

SVP’s Forecasted coincident Peak Load / Forecasted Peak Load in the PG&E TAC Area * Total LCR in the PG&E TAC Area.

http://www.caiso.com/Documents/Final2015LocalCapacityTechnicalStudyReportApr30_2014.pdf


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The following is a list of SVP’s Local Capacity resources. The Net Qualifying

Capacity (NQC) for these resources are derived from the CAISO “2015 LOCAL CAPACITY TECHNICAL ANALYSIS FINAL REPORT”. These resources clearly exceed SVP’s requirements to provide LCR. SVP may provide excess capacity to third parties. Actual available NQC being reported to the CAISO will reduce the available NQC from each unit. These reductions are not reflected below.

The following is a list of SVP’s Local Capacity resources which are located within, or are deliverable to, a CAISO defined load pocket and may be used by SVP to fulfill its LCR. The numbers in the below list below reflect SVP’s 2015 calendar year RA capacity sales to other parties (resulting in some NQC reductions reflected in the table):

Qualifying Capacity Resources

RESOURCE_ID LOCAL AREA GENERATOR NAME NQC*6

ALMEGT_1_UNIT 1 Bay Area ALAMEDA GT UNIT 1 4.9

ALMEGT_1_UNIT 2 Bay Area ALAMEDA GT UNIT 2 0.0

BEARDS_7_UNIT 1 Stockton BEARDSLEY HYDRO 7.1

CONTAN_1_UNIT Bay Area GRAPHIC PACKAGING COGEN 7

CSCCOG_1_UNIT 1 Bay Area SANTA CLARA CO-GEN 2

CSCGNR_1_UNIT 1 Bay Area GIANERA PEAKER UNIT 1 24

CSCGNR_1_UNIT 2 Bay Area GIANERA PEAKER UNIT 2 24

DONNLS_7_UNIT Stockton DONNELLS HYDRO 72

DUANE_1_PL1X3 Bay Area DVR POWER PROJECT 147.8

LODI25_2_UNIT 1 Stockton LODI GAS TURBINE 7.5

LODIEC_2_PL1X2 Sierra Lodi Energy Center 17

NCPA_7_GP1UN1 NCNB NCPA GEO PLANT 1 UNIT 1 13.8



TULLCK_7_UNITS Stockton TULLOCH HYDRO AGGREGATE 19.5

WHEATL_6_LNDFIL Sierra G2 ENERGY, OSTROM ROAD 1.5

ZOND_6_UNIT Bay Area ZOND WINDSYSTEMS INC. 3,6

CAYTNO_2_VASCO WEBER_6_FORWRD

Bay Area Stockton

AMERESCO VASCO (Livermore) AMERESCO FORWARD (Manteca)

4.3 4.2

Local Requirement 211 MW Total Local Capacity 364.5 SVP has much more local capacity than needed in order to meet its Local Capacity requirements for the year 2015.

6 If a particular resource’s NQC changes throughout each month of the year, the NQC value shown corresponds to the value in the month of SVP’s expected coincident peak load, which is projected to occur June of 2015



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Qualifying Capacity Criteria

Net Dependable Capacity

Net Dependable Capacity (NDC) defined by NERC Generating Availability Data System (GADS) information will be used to determine the Qualifying Capacity of some of the resource types identified in this IERP. For the purpose of these Sections, NDC is equal to Gross Dependable Capacity (GDC) less the unit capacity utilized for the unit station service or auxiliaries. GDC is equal to Gross Maximum Capacity (GMC) modified for seasonal limitations over a specified period of time. GMC is the maximum capacity a unit can sustain over a specified period of time when not restricted by seasonal or other deratings.

SVP System

As defined in the MSS, the term “SVP System” means all transmission and distribution facilities within the CAISO Control Area owned or controlled by SVP and all Generating Units within the CAISO Control Area owned (in whole or in part) or controlled by SVP.

Jointly-Owned Generation Facilities

A jointly-owned generation facility is either (a) identified in Schedule 14 of the MSS or identified in Schedule 14 of the MSSA, (b) located within or outside of the NCPA System (as the term “NCPA System” is defined in the MSSA) or the SVP System, (c) a Participating Generator, or (d) a Qualifying Facility to be considered Qualifying Capacity. The Qualifying Capacity for the entire facility will be determined based on the type of resource as described elsewhere in this IERP. SVP’s entitlement to the Qualifying Capacity of the facility may encompass the entire Qualifying Capacity of the facility, or may be limited to a portion of the Qualifying Capacity of the facility. The total amount of Qualifying Capacity that may be identified in the annual and/or the monthly Resource Adequacy Plan is limited to the total jointly-owned facility Qualifying Capacity determined in this IERP.

Thermal

Thermal generating facilities which are identified in Schedule 14 of the MSS or MSSA, located within the NCPA System or SVP System, a Participating Generator, or a Qualifying Facility are considered Qualifying Capacity. Thermal generating facilities that are not required to sign a Participating Generator Agreement pursuant to Section 2.2.1 of the CAISO Participating Generator Agreement are also eligible to be identified as Qualifying Capacity. The Qualifying Capacity of a thermal facility will be based on Net Dependable Capacity as defined in this IERP.

Hydro

Hydro generating facilities which are identified in Schedule 14 of the MSS or MSSA, located within the SVP System or NCPA System, a Participating Generator, or a Qualifying Facility shall be considered Qualifying Capacity. The Qualifying Capacity of a pond or pumped storage hydro facility will be based on Net Dependable Capacity as defined in

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this IERP, minus variable head de-rate based on current reservoir levels with dry year (1-in-5 dry year) forecasted inflows. The Qualifying Capacity of a run-of-river hydro facility will be based on Net Dependable Capacity as defined in this IERP, minus actual or forecasted conveyance flow, stream flow, or canal head de-rate. Although SVP’s Grizzly hydroelectric facility is not listed in Schedule 14 of the MSS, the capacity available to SVP under the SVP-PG&E Grizzly Agreement (an Existing Transmission Contract or ETC) shall be considered Qualifying Capacity.

Unit-Specific Contracts

Unit-specific power purchase and supply contracts fully qualify as RA Qualifying Capacity. A generating facility which is identified in a unit-specific contract and is identified in Schedule 14 of the MSS or MSSA, is located within or outside of the SVP System or NCPA System, is a Participating Generator, or is a Qualifying Facility, shall be considered Qualifying Capacity. Generating facilities identified in the contract that are not required to sign a Participating Generator Agreement pursuant to Section 2.2.1 of the CAISO Participating Generator Agreement are also eligible to be identified as Qualifying Capacity.

Firm Physical Contracts

Firm energy contracts which contain provisions to ensure reliable physical delivery, such as Force Majeure and due diligence requirements, or that contain provisions that identify non-delivery as a default condition subject to contract termination, and which may or may not contain Liquidated Damages (as generally reflected in Service Schedule C of the Western Systems Power Pool Agreement or the Firm Liquidated Damages (LD) product of the Edison Electric Institute pro forma agreement, or any other similar firm energy contract that provides the seller with an obligation to compensate the buyer for any additional costs of replacement energy) provisions, will fully qualify as RA Qualifying Capacity.

Wind and Solar

The Qualifying Capacity of firm wind and solar generating facilities, located inside or outside the CAISO Control Area, with backup sources of generation, will be based on Net Dependable Capacity as defined in this IERP.

The Qualifying Capacity of wind and solar facilities located inside or outside the CAISO Control Area, without backup sources of generation, shall be based on their monthly historical noon to 6:00 p.m. capacity factor, using a three-year rolling average.

New wind and solar generating facilities located inside or outside the CAISO Control Area, without backup sources of generation which do not have three years of historical performance data, will be assigned a default Qualifying Capacity for each year of missing historical performance as follows:

The Qualifying Capacity of another solar or wind generator with historical data located in the same weather regime with similar technology adjusted for the

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nameplate capacity ratio of a new generator and the similarly situated proxy generator.

The default Qualifying Capacity values shall be replaced annually with actual performance data as the data becomes available to form a three year rolling average.

Geothermal

Geothermal generating facilities which are identified in Schedule 14 of the MSSA, located within the SVP System or NCPA System, a Participating Generator, or a Qualifying Facility are considered Qualifying Capacity. The Qualifying Capacity of a geothermal facility is based on Net Dependable Capacity, adjusted for steam field degradation.

Treatment of Qualifying Capacity of QFs

If in the future SVP decides to acquire and identify Qualifying Capacity in either the annual or monthly RA Plan sourced from QFs, the ROC shall, with the approval of the City Council as appropriate, determine the Qualifying Capacity Criteria for QFs.

Dispatchable Demand Resource and Participating Loads

Dispatchable Demand resources, Non-Dispatchable Demand resources or similar power reduction pool plans which are identified in Schedule 10B or Schedule 11 (Emergency Action Plan) of the MSS or MSSA, or are located within the SVP System or the NCPA System shall be considered Qualifying Capacity. Participating Loads which are identified in Schedule 14 of the MSS or MSSA or located within the SVP System or the NCPA System shall be considered Qualifying Capacity. Dispatchable Demand resources, Non-Dispatchable Demand resources, Participating Loads and power reduction pool plans which are available at least 48 hours during the five summer months (May to September) shall be counted in either the annual or monthly RA Plan as Qualifying Capacity, provided that the conditions/provisions of the power reduction pool program (as specified in Schedule 11 of the MSS) and SVP retail customer contracts are honored at all times. If a Dispatchable Demand resource or Participating Load is available for the minimum requirement, the megawatt quantity reduction stipulated in the contract or program shall be treated as supply and be eligible to be listed as Qualifying Capacity. If a Non-Dispatchable Demand resource is available for the minimum requirement, the megawatt quantity reduction stipulated in the contract or program, adjusted to reflect the contract or programs average historical performance, shall be treated as supply and shall be eligible to be listed as Qualifying Capacity.

Facilities Under Construction

The Qualifying Capacity for facilities under construction shall be determined based on the type of resource as described elsewhere in this IERP. The facility will be eligible to be identified as Qualifying Capacity in SVP’s annual or monthly RA Plan pursuant to the anticipated operational date of the facility.

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Dynamically Scheduled System Resources

Eligibility as Qualifying Capacity of a Dynamically Scheduled System Resource shall be contingent upon SVP securing transmission through any intervening Control Areas for the resource entitlement that cannot be curtailed for economic reasons or bumped by higher priority transmission. The Qualifying Capacity provided by a Dynamically Scheduled System Resource shall be limited by SVP’s allocated import capacity at the import Scheduling Points, as agreed upon between SVP and the CAISO, consistent with the MSS.

Non-Dynamically Scheduled System Resources

The Qualifying Capacity provided by a Non-Dynamically Scheduled System Resource shall be limited by SVP’s allocated import capacity at the import Scheduling Points, as agreed upon between SVP and the CAISO consistent with the MSS.

SVP System Transmission Ownership Rights

The capacity entitlement, measured in megawatts, of SVP’s transmission ownership rights in the CAISO Control Area at the Control Area Scheduling Points shall be eligible to be identified as Qualifying Capacity in the annual and monthly Resource Adequacy Plans. The capacity entitlement of SVP’s transmission ownership rights in the CAISO Control Area at the Control Area Scheduling Points are listed in Schedule 13 of the MSS and/or the MSSA, and include but are not limited to the COTP Terminus (as described in the CAISO-SMUD Interconnected Control Area Operating Agreement) and the Plumas-Sierra Rural Electric Cooperative transmission ownership rights up to the Marble Substation Scheduling Point (as described in the CAISO’s Interconnected Control Area Operating Agreement with Sierra Pacific Power Co. for the Marble Substation intertie).

San Juan Generating Station

SVP, through its participation in the M-S-R PPA, has an ownership interest in the San Juan Generating Station located in northern New Mexico. SVP also has an ETC path across the CAISO Control Area to deliver the San Juan Generating Station’s generation into the CAISO to serve SVP’s load. SVP’s share of this resource is eligible to be identified as Qualifying Capacity.

Western Area Power Administration

SVP, as a municipal utility and hence as a Western preference power customer, has an entitlement to a portion of Central Valley Project (CVP) generation. SVP’s share of these resources is eligible to be identified as Qualifying Capacity.

Resources Division

CITY OF SANTA CLARA; End of 2015 Update

SVP’S INTEGRATED ENERGY RESOURCE PLAN UPDATE

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INTRODUCTION

The 2014 Integrated Energy Resource Plan (IERP) looked at many of the issues influencing Silicon Valley Power and how the utility could best meet customer needs over the next 20 years. Three scenarios were analyzed with the PLEXOS modeling software, looking at potential future resource mixes and the costs to dispatch these resources under different situations. Variables important to pricing and availability of future supplies were included in developing the costs to dispatch resources in different load profiles (low, medium and high changes in demand). For this first review, the scenarios were compared with the actual customer load and resources one year later.

The results show that while load forecasts had overestimated actual sales in 2013 and 2014, by early 2015 electric consumption began to increase rapidly and outpaced even the most optimistic outlooks. Fuel prices, predominantly natural gas, dropped dramatically to levels even less than low cost scenarios used for the IEPR. These two items are likely factors behind the ongoing slump in energy efficiency as a percentage of consumption and the continuing difficulty in finding economic locations for storage.

As SVP looks toward a future with greater reliance on environmentally preferred resources, such as renewable energy, efficiency and storage, it must continue to balance its reliability concerns and reasonable customer rate expectations against overriding policy objectives to reduce greenhouse gas emissions and protect the environment.

LOAD

When forecasted load was compared against actual sales for the past three calendar years, forecasts were too optimistic for 2013 and 2014. However, in 2015 loads increased significantly, primarily from greater round-the-clock use at some larger customers (per Key Account Representatives). Peak demand slightly exceeded the high load scenario.

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Forecasted Consumption and Peak Demand for 2015-2024

Source: PLEXOS runs; November and December 2014

The IERP used forecasts that assumed total load (MWh) and peak demand (MW) would increase at 1% per year. Monthly usage patterns were expected to remain relatively flat, with only slight variations each month. Historically, maximum load requirement has only increased somewhat in the summer due to SVP’s customer mixture, where a majority of sales come from industrial companies operating around the clock. In addition, Santa Clara’s moderate weather results in a fairly low need for air conditioning and other peak demands. As can be seen from 2015 results through October, however, this may be changing. Long term load patterns will need to be monitored to see if the demand profile is changing.

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GENERATION

Utility generation and unit cost forecasts were analyzed for all three scenarios in the 2014 IERP. The forecasted period was graphed to visualize the overall trend in the baseline scenarios for rain and gas prices, as well as periods with droughts/low gas prices and high water/gas prices. Next, a sample year (in the case below, FY 2019), after the San Juan Coal station is to have closed, was used to look at monthly projected generation in comparison to load. Actual generation patterns for the past two completed fiscal years were compared to the FY 2019 forecast.

Forecasted 2014 – 2024 Generation by Type Compared to Consumption



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As seen below, the effects of the severe drought were obvious in reduced generation by all forms of hydro facilities. Wind production at Big Horn was also much less, particularly in the first half of CY 2015. Solar generation was somewhat higher than forecasted. Due to the lowered capacity of hydro and wind, as well as lower natural gas prices, gas was relied upon to fill up much of the gap.

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The impact of reduced wind, large and small hydro generation during the 2015 spring months, when hydro is normally at its peak production, in comparison to the related increases in natural gas generation can be clearly identified in the graph below.

ENVIRONMENTALLY PREFERRED RESOURCE PROCUREMENT

Energy Efficiency

Over the past seven years, EE programs have provided lifetime savings at a cost comparable to a supply resource (between $25 and $60 per MWh). These programs have been successful at a significant benefit to cost level, with ratios between 1.8 and 5.6 since 2008 (where a number great than 1 is a beneficial program). However, each year’s programs have typically provided 1% or less savings on an annual basis compared to usage. The percentage of savings compared to sales has dropped annually since FY 2009. This is likely because electricity remains relatively inexpensive compared to implementing efficiency, mostly from historically low natural gas prices and the ongoing difficulty in achieving efficiencies greater than building standards. While customers and the utility gain significant benefits from implementing EE equipment and processes, the utility can only count EE savings in its programs if these installations or changes in behavior are not required under current codes and standards. Customers and contractors also find it difficult to meet California Energy Commission requirements for some upgrades, in particular commercial lighting. Assuming that the average equipment replacement or building upgrade has an average 10 to 15 year life, current and historical EE programs have a cumulative reduction on total load in Santa Clara of about 10% per year.

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Historically Low Cost of Natural Gas

Source: SVP Public Benefit Annual Reports and Utility Fact Sheets

Negawatt costs (MWh reductions) through efficiency are cost-effective and comparable to other forms of supply. They are expected to continue to remain cost-competitive with some other resources. However, given natural gas’s current low prices at this point in time, it is difficult for EE to compete with that purely on a price basis. When looking at the value of meeting state policy goals to reduce Greenhouse Gases through increased efficiency and use of other environmentally preferred procurement, such as

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Axis Title

Gas Prices Actual Vs. Forecast 2014-2015

Avg PG&E City Gate Base Forecast Cost of Gas at DVR

High Forecast Cost of Gas at DVR Low Forecast Cost of Gas at DVR

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renewable generation, particularly solar and wind, energy efficiency remains a high priority.

Energy Storage

Energy Storage costs are continuing to fall and many electric utilities nationwide are procuring different types of storage for a variety of specific applications. These utilities include in particular the investor owned utilities who are required by the CPUC to invest in a certain amount of storage technologies. SVP has completed its installation of battery storage at 30 kW at EV chargers and will be monitoring the cost and operation of these facilities. In addition, staff has met on several occasions with potential battery storage integrators to discuss potential locations and applications in Santa Clara. While economic options for SVP have yet to be found, staff continues to look for potential R&D locations and uses.

Renewable Energy Generation

To meet state policy objectives set in recently adopted SB350, SVP will need to increase its percentage of generation coming from small hydro, solar, wind, geothermal and other renewable resources. Ending SVP’s participation in the coal generation at the San Juan facility in New Mexico will significantly assist in meeting Greenhouse Gas reductions goals. In addition, SVP continues to seek new, cost-effective renewable sources of generation, particularly those that interact well with the load pattern in Santa Clara. With the price of renewable generation, especially solar, continuing to decrease and becoming more competitive with natural gas and other generation sources, the task of a 50% Renewable Portfolio Standard by 2030 is definitely achievable.

Source: SVP website