HomeMy WebLinkAboutRESO 9802 1
Resolution No. 9802
Resolution of the Council of the City of Palo Alto Approving the 2018
Electric Integrated Resource Plan (EIRP), Updated Renewable
Portfolio Standard Procurement Plan and Enforcement Program, and
Related Documents
R E C I T A L S
A. Senate Bill 350 was adopted in 2015, establishing a requirement that requires
publicly owned utilities (POUs) with an average load greater than 700 GWh (in the 201316
period) to adopt Integrated Resource Plans (IRP) by January 1, 2019, submit them to the
California Energy Commission (CEC), and update them at least once every five years thereafter.
B. Based on historical data, the City of Palo Alto is one of 16 California POUs that
are required to file an IRP.
C. The CEC is required to review POU IRPs for consistency with Public Utilities Code
9621 and recommend corrections to deficiencies in the plans, according to the Publicly Owned
Utility Integrated Resource Plan Submission and Review Guidelines (POU IRP Guidelines) most
recently adopted by the CEC in August 2018.
D. The POU IRP Guidelines require POUs to submit certain supporting information
along with the IRP, including a set of four standardized tables and a Renewable Portfolio
Standard (RPS) Procurement Plan.
E. The City of Palo Alto first adopted an RPS Procurement Plan on December 12,
2011 (Resolution 9215) and last updated it on November 12, 2013 (Resolution 9381).
F. The City of Palo Alto also adopted an RPS Enforcement Program on December
12, 2011 (Resolution 9214), which has not been updated since that date.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. The Council hereby approves the 2018 Electric Integrated Resource Plan
(Attachment B).
SECTION 2. The Council hereby approves the four standardized tables that
accompany the 2018 EIRP (Appendix D to Attachment B).
SECTION 3. The Council hereby approves the updated Renewable Portfolio Standard
Procurement Plan that will be submitted to the CEC in conjunction with the 2018 EIRP
(Appendix B to Attachment B).
SECTION 4. The Council hereby approves the updated Renewable Portfolio Standard
Enforcement Program (Appendix C to Attachment B).
DocuSign Envelope ID: 4A3FA916-8CAD-4C49-B497-C2ECC62DF6F4
DocuSign Envelope ID: 4A3FA916-8CAD-4C49-B497-C2ECC62DF6F4
SECTION 5. The Council finds that the adoption of this resolution approving the EIRP
and related documents is not a project subject to California Environmental Quality Act {CEQA)
review because adoption of this resolution is an administrative government activity that will
not result in any direct or indirect physical change to the environment as a result {CEQA
Guidelines section 15378{b){S)).
INTRODUCED AND PASSED: December 3, 2018
AYES: DUBOIS, FILSETH, FINE, HOLMAN, KNISS, KOU, SCHARFF, TANAKA, WOLBACH
NOES:
ABSENT:
ABSTENTIONS:
ATIEST:
City Clerk
APPROVED AS TO FORM:
Assistant City Attorney
2
APPROVED:
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City Manager
Utilities General Manager
Director of Administrative Services
City of Palo Alto
2018 Electric Integrated Resource Plan
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Table of Contents
i
Table of Contents
Executive Summary.................................................................................................................... 1I.
CEC IRP Guidelines & Required Elements................................................................................. 3A.
Public Process Summary ........................................................................................................... 4B.
Background & Achievements to Date ......................................................................................... 6II.
CPAU History and Mission Statement...................................................................................... 6A.
Previous IRPs & Recent Accomplishments............................................................................... 6B.
Changing Planning Environment .............................................................................................. 7C.
Increasing DER Penetration & Load Profile Uncertainty ................................................... 7i.
GHG Emission Reductions .................................................................................................9ii.
Renewable Portfolio Standards (RPS)............................................................................... 9iii.
Energy Efficiency ............................................................................................................. 10iv.
Overview of EIRP methodology .............................................................................................. 10D.
Forecast Methodology for Energy and Peak Demand................................................................ 12III.
Description of Econometric Forecast Models ........................................................................ 14A.
Energy Econometric Model ............................................................................................. 14i.
Peak Demand Econometric Model.................................................................................. 14ii.
Description of Distributed Energy Resources Forecasts ........................................................ 14B.
Energy Efficiency Forecast............................................................................................... 16i.
Solar Photovoltaic Forecast............................................................................................. 17ii.
Transportation Electrification Forecast........................................................................... 17iii.
Energy Storage Forecast .................................................................................................. 17iv.
Demand Response Forecast............................................................................................ 18v.
Electrification of Space and Water Heating Forecast ..................................................... 18vi.
SB 338 Requirements ...................................................................................................... 18vii.
Existing Resource Portfolio ....................................................................................................... 20IV.
Energy Efficiency & Local Renewable Generation.................................................................. 21A.
Energy Efficiency ............................................................................................................. 21i.
Local Renewable Generation.......................................................................................... 22ii.
Hydroelectric Resources ......................................................................................................... 23B.
Western Base Resource .................................................................................................. 23i.
Calaveras......................................................................................................................... 25ii.
Renewable Energy Resources.................................................................................................26C.
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Table of Contents
ii
Wind PPAs.......................................................................................................................26i.
Landfill Gas (LFG) PPAs .................................................................................................... 26ii.
Solar PPAs ........................................................................................................................ 26iii.
Market Purchases & RECs....................................................................................................... 27D.
COBUG.................................................................................................................................... 27E.
CaliforniaOregon Transmission Project (COTP)..................................................................... 27F.
Resource Adequacy Capacity.................................................................................................. 28G.
Future Procurement Needs and Portfolio Rebalancing .............................................................. 29V.
Needs Assessment: Energy, RPS, Resource Adequacy Capacity ............................................ 29A.
Portfolio Rebalancing Analysis ............................................................................................... 30B.
Portfolio Expected Net Value .......................................................................................... 33i.
Portfolio Fit ...................................................................................................................... 34ii.
Portfolio Cost Uncertainty and Management .................................................................35iii.
Supply Costs & Retail Rates ...................................................................................................... 36VI.
Transmission & Distribution Systems........................................................................................ 37VII.
Transmission System .............................................................................................................. 37A.
Distribution System................................................................................................................ 37B.
Lowincome Assistance Programs ............................................................................................. 38VIII.
Localized Air Pollutants ............................................................................................................ 39IX.
Electric Vehicle Programs ....................................................................................................... 39A.
Local Renewable Energy Programs ........................................................................................ 39B.
Electrification of Space and Water Heating Programs ........................................................... 39C.
Refrigerant Recycling Program ............................................................................................... 40D.
Path Forward & Next Steps ...................................................................................................... 41X.
Recommended Portfolio ........................................................................................................ 41A.
GHG Emissions ........................................................................................................................ 42B.
Scenario Analysis .................................................................................................................... 42C.
Next Steps............................................................................................................................... 43D.
Key Issues to Monitor & Attempt to Influence ...................................................................... 43E.
Appendices......................................................................................................................... XI—1XI.
Key Supplemental Reports and Documents....................................................................... XI—1A.
RPS Procurement Plan ........................................................................................................ XI—2B.
RPS Enforcement Program ............................................................................................... XI—16C.
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Table of Contents
iii
Standardized IRP Tables ...................................................................................................XI—20D.
Capacity Resource Adequacy Table (CRAT) .............................................................. XI—20i.
Energy Balance Table (EBT) ....................................................................................... XI—21ii.
GHG Emissions Accounting Table (GEAT) .................................................................XI—22iii.
RPS Procurement Table (RPT) ................................................................................... XI—23iv.
List of Figures
Figure 1: The Duck Curve – Net Load in California with Penetration of Intermittent Generation............. 8
Figure 2: Palo Alto Power Supply in 2012 and 2018................................................................................. 10
Figure 3: Annual Energy Forecast including DERs (20182030) ................................................................ 13
Figure 4: Impact of DERs on Hourly Summer Load Shape in 2030 ........................................................... 13
Figure 5: Projected Palo Alto Electric Supply Mix in CY 2020 by Resource Type ..................................... 20
Figure 6: Palo Alto’s RPS Generation Projections and RPS Compliance Requirements .......................... 29
Figure 7: Expected Net Value of New Resources and Western Relative to Market Value....................... 33
Figure 8: Average Hourly Load and Generation Profiles for Each Month for Western and Potential New
Resources (Normalized to Average Hourly Load) ............................................................................. 34
Figure 9: Palo Alto’s Projected Resource Supply Mix in 2030.................................................................. 41
Figure 10: CPAU Electric Supply GHG Emissions (20052030).................................................................. 42
List of Tables
Table 1: California Energy Market Changes Since 2012............................................................................. 1
Table 2: City of Palo Alto EnergyRelated Changes Since 2012.................................................................. 2
Table 3: Public Process Summary for Development of the 2018 EIRP....................................................... 5
Table 4: Projected Number of DER Systems (20172030) ........................................................................ 15
Table 5: Projected Contribution to Energy Sales of DER Systems (20172030) ....................................... 15
Table 6: Palo Alto’s Resource Adequacy Capacity Portfolio ..................................................................... 28
Table 7: Relative Merits of Candidate Resources Considered to Rebalance Supply Portfolio................. 32
List of Key Supplemental Reports and Documents
1.NCPACAISO Metered SubSystem Agreement
2.TenYear Electric Energy Efficiency Goals (2017)
3.Energy Storage Assessment Report (2017)
4.Proposed Distributed Energy Resources Plan (2017)
5.Distribution System Assessment Report (2018)
6.Demand Side Management Annual Report (2018)
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Section I: Executive Summary
1
Executive Summary I.
The City of Palo Alto’s 2018 Electric Integrated Resource Plan (EIRP) is a comprehensive plan for
developing a portfolio of power supply resources to meet the utility’s objective of providing safe,
reliable, environmentally sustainable, and costeffective electricity services while addressing the
substantial risks and uncertainties inherent in the electric utility business. The EIRP also supports the
City’s mission to promote and sustain a superior quality of life in Palo Alto. In partnership with our
community, our goal is to deliver costeffective services in a personal, responsive and innovative
manner.
The IRP meets the requirements of California Senate Bill (SB) 350 (de León, Chapter 547, Statutes of
2015), which requires publicly owned utilities (POUs) with an average annual energy load greater than
700 gigawatthours (GWh) to submit an IRP at least every five years to the California Energy
Commission (CEC).
The EIRP discusses current and anticipated California regulatory and policy changes facing Palo Alto
and the electric utility industry. Additionally, the IRP presents the analyses conducted and underlying
assumptions, and outlines a resource plan to reliably and affordably meet customers’ energy needs
through calendar year 2030.
The electric utility industry has undergone significant changes since Palo Alto prepared its last Long
term Electric Acquisition Plan (LEAP) update in 2012, with a major shift underway towards greater
levels of variable, distributed, lowemissions generation, along with an expanding suite of regulatory
mandates that the City must satisfy. Table 1 provides an overview of some of the key structural
changes in California’s electricity market that must be addressed in the 2018 EIRP, compared to their
status at the time of the 2012 LEAP update.
Table 1: California Energy Market Changes Since 2012
EIRP Topic 2012 Status 2018 Status
GHG Emissions Targets Statewide emissions reduced to
1990 levels by 2020 40% below 1990 levels by 2030
Cap and Trade Authorized through 2020 Authorized though 2030
Renewable Procurement 33% by 2020 and beyond 50% by 2030 and beyond
Distributed Generation Modest growth High growth
Energy Efficiency Utilityspecific targets (all cost
effective energy efficiency)
Statewide goal of doubling energy
efficiency savings by 2030
Energy Storage No explicit requirement Requirement to study adoption of
targets
Transportation
Electrification No explicit requirement Requirement to address
procurement of EV infrastructure
Structured Markets Hourly market Intrahour market
Resource Adequacy Local and system capacity
requirements
Local, system, and flexible
capacity requirements
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Section I: Executive Summary
2
Similarly, Palo Alto itself has undergone a myriad of changes over the past six years—both in its long
term planning goals and in how it uses electricity currently. Table 2 describes some of the major
changes and accomplishments in Palo Alto since 2012, from dramatic changes in the City’s power
supply and emissions reduction targets, to considerable growth in local solar generation and electric
vehicles (EVs).
Table 2: City of Palo Alto EnergyRelated Changes Since 2012
Topic 2012 Status 2018 Status
Communitywide
GHG Emissions
(from electricity,
natural gas and
transportation)
Goal:Reduce GHG emissions to 15%
below 2005 levels by 2020.
Achieved: 22% below 2005 emission
levels (28% below 1990 emissions
levels).
Goal:Reduce GHG emissions to 80%
below 1990 by 2030.
Achieved: 43% below 1990 emission
levels.
Electric Supply
Portfolio
Goal:33% RPS by 2015
Achieved: 21% RPS
Goal:50% RPS by 2030; 100% Carbon
Neutral by 2015
Achieved: 58% RPS; 100% Carbon Neutral
Local Solar PV
Systems
Goal:0.71% of load by 2017
Achieved: 0.57% of load
(502 systems)
Goal:4% of load by 2023
Achieved: 1.94% of load
(1,081 systems)
Energy Efficiency Goal:0.63% avg. annual load
savings; 4.8% cumulative savings
(20142023)
Achieved: 0.68% of avg. annual
load; 4.2% cumulative 6year savings
(20072012)
Goal:0.75%avg. annual load savings;
5.7% cumulative savings
(20182027)
Achieved: 0.73% of avg. annual load;
4.4%1 cumulative 6year savings
(20132018)
Energy Storage Goal:No explicit goal.Goal:No explicit goal or rebates as not
yet costeffective. Facilitate customer
adoption in coordination with Building
department.
Transportation
Electrification
Goal:Support California State goal
Achieved: approx. 200 EVs
registered in Palo Alto.
Goal:Target 90% EVs by 2030
Achieved: approx. 3,000 EVs registered in
Palo Alto; 60 public EV chargers;
Incentives for EV charger installation.
Annual Energy
Load 972 GWh 925 GWh
Summer Peak
Capacity Load 170 MW 182 MW
Average Retail
Rate2 11.6 cents/kWh 13.9 cents/kWh
1 Includes savings related to Codes and Standards changes, as well as estimated savings for 2018.
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Section I: Executive Summary
3
The EIRP planning period is from 2018 to 2030. Through 2028, the City of Palo Alto Utilities (CPAU) has
sufficient renewable contracts to supply over 50% of the City’s needs. The City’s first longterm
renewable contract—for wind power—expires at the end of 2021 and the other wind contract and all
five landfillgasto energy contracts expire in the late 2020’s or early 2030’s, while the solar contracts
all extend beyond 2040. The City’s contract with the Western Area Power Administration (WAPA) for
hydroelectric resources, which supplies nearly 40% of the City’s energy needs in a normal hydro year,
expires at the end of 2024. A major consideration for the EIRP is whether to renew the contract with
WAPA (and if so, at what participation level) and/or seek other renewable supplies.
CPAU expects to continue operating within the Northern California Power Agency’s (NCPA) Metered
SubSystem Aggregation (MSSA) Agreement with the California Independent System Operator (CAISO).
Under this agreement, NCPA balances CPAU’s loads and resources to comply with CAISO planning and
operating protocols. With resources available under the NCPA MSSA Agreement, Palo Alto has access
to sufficient system, local, and flexible capacity, as well as resources to provide ancillary services to
reliably meet City loads.
Costs are projected to increase through 2030, primarily due to system upgrade costs, increasing
environmental regulations, and renewable integration costs (which are part of the tradeoff between
pursuing sustainable electricity supplies and reducing overall supply costs). Costs are increasing, but
retail energy sales are decreasing due to increases in energy efficiency and local solar installations, and
are further expected to decline in 2020 and beyond due to building codes mandating new homes be
net zero annual energy. Part of this reduction in electrical energy use is expected to be offset by higher
penetration of electric vehicles and electrification of natural gas appliances.
CPAU staff will provide public updates on the progress, successes, and new challenges over the
implementation period of this IRP.
CEC IRP Guidelines & Required Elements A.
The schedule and structure of the EIRP process is being guided in large part by requirements imposed
by SB 350,3 which states that Palo Alto’s IRP must be adopted by Council by January 1, 2019, submitted
to the CEC by April 30, 2019, and updated at least once every five years thereafter. At a minimum,
Sections 9621 and 454.52 of the State Public Utilities Code require that the City’s IRP will need to:
Ensure procurement of at least 50% renewable resources by 2030 (see EIRP Sections II.B,
II.C.iii, V.A, X.A)
Meet Palo Alto’s share of the greenhouse gas emission reduction targets established by the
California Air Resources Board (CARB) for the electricity sector, to enable California to
2 Retail rate and energy efficiency values are for Fiscal Years 2012 and 2018; the rest of the values in Table 2 are for
Calendar Years 2012 and 2018.
3 SB 350 also requires the doubling of energy efficiency savings targets by 2030 and establishes a new Renewable Portfolio
Standard (RPS) to meet 50% of the City’s load from applicable renewable supplies by 2030. The 10Year Energy Efficiency
Potential Plan approved by Council in March 2017 addresses the new energy efficiency savings requirements and the City
expects to achieve an RPS of 58% in 2018.
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Section I: Executive Summary
4
achieve the economy wide greenhouse gas emissions reductions of 40% from 1990 levels by
2030 (Sections II.B, II.C.ii, X.B)
Minimize impacts to customer bills (Section VI)
Ensure system and local reliability, including in the hour of peak net demand (Sections
III.B.vii, IV.E, IV.F, VII)
Strengthen the diversity, sustainability, and resilience of the bulk transmission, distribution
systems and local communities (Sections II.B, IV.A.ii, IV.E, IV.F, VII, VIII)
Enhance distribution systems and demandside energy management (Sections IV.A.i, VII.B)
Minimize localized air pollutants and other greenhouse gas emissions with early priority to
disadvantaged communities (Sections II.B, IV.A.ii, IX)
Address the following procurement topics:
o Energy efficiency and demand resources that are cost effective, reliable and feasible
(Sections II.B, II.C.iv, III.B.i, IV.A.i)
o Energy storage (Section III.B.iv)
o Transportation electrification (Section II.B, III.B.iii)
o A diversified procurement portfolio of short term electricity, long term electricity,
and demand response products (Section III.B.v)
o Resource adequacy (Sections IV.G, V.A)
The City currently has the resources and systems in place needed to achieve all of the objectives
addressed by these IRP requirements. In addition, CPAU is submitting the following four Standardized
Tables as part of the EIRP:
Capacity Resource Accounting Table (CRAT): Annual peak capacity demand in each year and
the contribution of each energy resource (capacity) in the POU’s portfolio to meet that
demand.
Energy Balance Table (EBT): Annual total energy demand and annual estimates for energy
supply from various resources.
RPS Procurement Table (RPT): A detailed summary of a POU resource plan to meet the RPS
requirements.
GHG Emissions Accounting Table (GEAT): Annual GHG emissions associated with each
resource in the POU’s portfolio to demonstrate compliance with the GHG emissions
reduction targets established by the California Air Resources Board (CARB).
This EIRP along with the four aforementioned Standardized Tables and the materials listed in the
Supporting Information section satisfy the IRP filing guidelines listed in Chapter 2 of the CEC guidelines.
Public Process Summary B.
Palo Alto staff has provided numerous reports and presentation related to various facets of the EIRP to
the Utilities Advisory Commission (UAC) over the past 15 months. The current EIRP report was
reviewed by the UAC on September 5, 2018 and October 3, 2018, before being presented to the
Finance Committee and City Council for approval in October and November 2018. Table 3 below lists
all public presentations related to the EIRP, with links to the associated reports.
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Section I: Executive Summary
5
Table 3: Public Process Summary for Development of the 2018 EIRP
Forum Date Topic Link
UAC 6/7/2017 Overview of CPAU’s EIRP Development Process Report
UAC 8/2/2017 Discussion of DER Plan Development Report
UAC 8/2/2017 Discussion of California Wholesale Energy Market and
Electric Portfolio Cost Drivers
Report
UAC 9/6/2017 Discussion of Hydroelectric Resources and Carbon Neutral
Portfolio Alternatives
Report
UAC 11/1/2017 Discussion of Proposed DER Plan Report
UAC 12/6/2017 Discussion of Renewable and Carbon Neutral Portfolio
Strategy
Report
UAC 4/12/2018 Assessment of CPAU’s Distribution System to Integrate DERs Report
UAC &
Council
5/2/18 &
5/21/2018 CPAU Demand Side Management Annual Report – FY 17
UAC,
Council
UAC 6/6/2018 Longterm Electric Portfolio Analysis Results and Options for
Rebalancing Portfolio in the Next Five to Ten Years
Report
UAC 9/5/2018 Discussion of 2018 EIRP Executive Summary, Objective &
Strategies, and Work Plan
Report
UAC 10/3/2018 Recommendation to Approve CPAU’s 2018 EIRP TBD
Finance 10/16/2018 Recommendation to Approve CPAU’s 2018 EIRP TBD
Council Nov 2018 Approval of CPAU’s 2018 EIRP TBD
An IRP represents a snapshot of a continuous process that evolves and transforms over time. The
conditions and circumstances in which utilities must make decisions about how to meet customers’
future electric energy needs are everchanging. The IRP process utilizes a methodology and framework
for assessing a utility’s everchanging business and operating requirements and adapting to factors
such as changing technology, regulations, and customer behavior. Assumptions, scenarios, and results
are all reviewed and updated as information and events unfold, and the process is continually revisited
under formal or informal resource planning efforts.
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Section II: Background & Achievements to Date
6
Background & Achievements to Date II.
CPAU History and Mission StatementA.
The City of Palo Alto Utilities' (CPAU) history began over one hundred years ago, in 1896, when the
water supply system was first installed. Two years later, the wastewater or sewer collection system
came online. In 1900, the municipal electric power system began operation, followed in 1917 by a
natural gas distribution system. While CPAU and the utilities industry have evolved dramatically over
118 years, the City has nonetheless maintained a consistent set of core values: Quality, Courtesy,
Efficiency, Integrity, and Innovation.
Palo Alto’s 2018 EIRP is a comprehensive planning document to guide longterm power planning
aligned with CPAU’s Mission Statement, which is “to provide safe, reliable, environmentally sustainable
and cost effective services.”4
Previous IRPs & Recent AccomplishmentsB.
Palo Alto regularly engages in longterm planning efforts related to its electric supply portfolio –
previously under the auspices of the Longterm Electric Acquisition Plan (LEAP) and in the future under
the EIRP.5 The last time the City completed a LEAP update was on April 16, 2012 (Staff Report 2710,
Resolution 9241). A few years later, in 2015, Senate Bill 350 (SB 350) was signed into law, and it
includes a requirement that publiclyowned utilities (POUs) serving loads greater than 700,000
megawatthours per year, such as Palo Alto, develop and adopt an IRP by January 1, 2019 and submit it
to the CEC by April 30, 2019 and every five years thereafter.6
As part of the 2012 LEAP update, the City Council approved a set of electric portfolio decisionmaking
Objectives and Strategies. At the outset of the current EIRP development process, staff developed an
updated Objective and Strategies. The current version, which aligns with the Utilities 2018 Strategic
Plan, is very similar to the ones adopted in 2012, with the new Objective and Strategies placing greater
emphasis on managing uncertainty related to resource availability and costs, regulatory uncertainty,
and the increased penetration of DERs.
The 2012 LEAP update included an Implementation Plan describing a set of ongoing tasks and new
initiatives for the City to undertake in order to satisfy the LEAP Objectives and Strategies. In carrying
out this Implementation Plan and other initiatives, Palo Alto has accomplished the following over the
past six years:
4 See the City of Palo Alto Utilities 2018 Strategic Plan, which includes the Mission Statement and Strategic Direction, here:
https://www.cityofpaloalto.org/civicax/filebank/documents/64505.
5 Staff will hereafter discontinue using the term LEAP and in the future use the term EIRP when seeking longterm electric
portfolio plan approvals from the Council.
6 The Clean Energy and Pollution Reduction Act of 2015 also raised the state’s renewable portfolio standard (RPS) to 50% by
2030 and required a doubling of energy efficiency savings by 2030. The primary objective of the IRP requirement in SB 350
is to ensure that the state’s large POUs are on track to reduce their greenhouse gas emissions, helping the state meet its
overall target of reducing GHG emissions to 40% below 1990 levels by 2030.
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Section II: Background & Achievements to Date
7
Developed a Carbon Neutral Electric Supply Plan and implemented it every year, beginning in
2013;
Increased the renewable energy supply from 21% of total load to 57% of total load;
Reduced GHG emissions related to electricity by 109,000 MT CO2e, helping reduce community
wide emissions by 43% compared to 1990 levels;
Developed and launched a Feedin Tariff program (Palo Alto CLEAN) for local renewable energy
projects, which currently has 1.6 MW of operating solar PV projects and an additional 1.3 MW
of solar projects in development;
Executed six new utilityscale solar contracts (totaling 153 MW of capacity), of which five
projects (127 MW capacity) are currently operational;
Achieved cumulative energy efficiency savings of 4.4%7 since 2012;
Coordinated with other departments on the installation of 60 public EV charger ports owned
and maintained by the City;
Approved a Local Solar Plan setting a goal of producing 4% of the community’s power supply
with local solar resources by 2023;
Approved an Electrification Work Plan to facilitate the electrification of natural gas loads in
buildings and facilitate adoption of electric vehicles;
Adopted aggressive energy efficiency goals which are 20% greater than a business as usual
approach and require new and innovative programs;
Adopted a Sustainability and Climate Action Plan with a goal of reducing community emissions
to 80% below 1990 levels by 2030;
Approved a new CPAU Strategic Plan; and
Continued to balance our own loads and resources under the CAISONCPA Metered Subsystem
Agreement.
Changing Planning Environment C.
Across the industry, integrated resource planning has undergone significant changes in recent years.
Traditionally, an IRP was an opportunity for a utility to evaluate the steady growth of its customer
loads over a 10+ year planning horizon, and develop a plan for meeting that load growth through
staged additions of new centralized thermal generation resources. Today’s IRPs, however, have to
consider how to integrate increasing volumes of variable and/or distributed generation in an
environment of declining loads and increasing regulatory mandates, all while maintaining reliability and
controlling costs. Accordingly, the objective of this IRP is to evaluate Palo Alto’s portfolio of resources
against the changing utility landscape and California’s environmental requirements, while
recommending strategies to ensure Palo Alto continues to meet the Council’s goals for affordability and
sustainability. The following is a description of some of the primary changes to the utilities planning
environment over the past several years.
Increasing DER Penetration & Load Profile Uncertainty i.
California’s resource mix has changed considerably as a result of its ambitious renewable mandates
and the rapidly declining costs of solar and wind resources. The shift to renewables has led to lower
(sometimes negative) market prices for power at certain times of the day, but has changed the daily
7 Includes savings related to Codes and Standards changes, as well as estimated savings for 2018.
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Section II: Background & Achievements to Date
8
load shape, which traditionally had a single peak lasting a few hours each day. The changing load shape
means new resources will be needed, and existing resources will need to be used differently, while
maintaining affordability for customers.
Solar and wind resources, unless paired with multihour energy storage systems, are intermittent
sources of generation, where energy output is a function of fuel availability (i.e., sunlight and wind). In
order to accommodate large volumes of intermittent resources, the system must include a sufficient
supply of highly responsive resources (or load) to follow this new demand profile, which is referred to
as net load (i.e., gross electricity consumption less intermittent generation). Recent capacity additions
for RPS compliance have largely been solar resources, which are introducing a surplus of energy supply
in the daytime hours, particularly in the spring and fall when renewable resources maintain higher
levels of output and customer loads are at seasonal lows.
Figure 1: The Duck Curve – Net Load in California with Penetration of Intermittent Generation
(Source: CAISO)
Figure 1 is a visual representation of the difference in load vs net load, highlighted by the beige area.
This is commonly referred to in the industry as the “duck curve.” As seen in Figure 1, solar contributes
to meeting load in the middle of the day, but rapidly trails off in the evening when load is still at or
near its daily peak. For reliability, this creates the added capacity challenge of being able to meet the
ramp, in addition to meeting peak demand. The resource fleet must be able to ramp down in the
morning to accommodate increases in solar output, then ramp back up very rapidly to meet peak
demand as solar generation diminishes with the setting sun. And while utilityscale solar is a challenge
for grid operators to integrate, the growing amounts of distributed solar are an even more vexing, as
these resources are essentially invisible to grid operators – thus they add a significant amount of
uncertainty to net load projections.
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Section II: Background & Achievements to Date
9
GHG Emission Reductionsii.
In 2006, California passed Assembly Bill (AB) 32, the California Global Warming Solutions Act. AB 32 is a
mandate for several sectors, including the electricity sector, to reduce GHG emissions to 1990 levels by
2020. In 2016, AB 32 was augmented by Senate Bill (SB) 32, which mandated a GHG emissions
reduction target of 40% below 1990 levels by 2030. California’s goal of reducing GHG emissions will be
achieved through a combination of market mechanisms (Cap and Trade) and prescriptive mandates
(RPS) to retire and replace high emitting resources with cleaner resources.
In order to achieve the SB 32 targets, many sectors of the economy – including industry,
transportation, and electricity – will need to reduce their GHG emissions. The state’s electric sector
GHG emissions in 1990 were 108 MMT CO2e. Reducing this amount by 40% creates a target of 64
MMT CO2e; however, CARB’s proposed range of 3053 MMT CO2e for the electricity sector is a 51% to
72% reduction, well in excess of the sector’s prorata share of the overall reduction target.8
The electricity sector is expected to surpass its prorata emission reduction share due primarily to the
50% RPS goal and aggressive energy efficiency requirements. SB 350 requires that POU IRPs not only
describe how they will meet their 2030 50% RPS target, but also how they will contribute to the
electricity sector's share of GHG emissions reductions by 2030. For benchmarking in this IRP and for
portfolio planning purposes, Palo Alto used the midrange value of 42 MMT CO2e as the 2030 target
for the electricity sector (of which Palo Alto’s loadbased pro rata share is 73,013 MT CO2e). These
goals are for planning purposes and not compulsory; however, if changes to the regulations occur, Palo
Alto will reflect those updates in its future resource planning efforts.
Renewable Portfolio Standards (RPS) iii.
One of the primary mechanisms for reducing GHG emissions in the electricity sector is the state’s RPS.
The state’s RPS program mandates that an increasing percentage of retail sales be served by qualifying
renewable generation. An RPS mandate was first imposed on Palo Alto by SB X12 in 2011, and
subsequently expanded by SB 350 in 2015. Currently, the major targets are 33% renewables by 2020,
and 50% by 2030. In addition to the minimum renewable generation procurement requirements, the
RPS program also includes portfolio balancing requirements and longterm contract requirements, as
described in Palo Alto’s RPS Procurement Plan (included as Supplementary Information).
Palo Alto satisfies its RPS requirements through a diverse portfolio of qualifying renewable resources –
wind, solar, bioenergy (landfill gas), and small hydro. In addition, approximately half of Palo Alto's load
is served by large hydro, a carbonfree resource that helps reduce GHG emissions, yet cannot be
counted for RPS compliance. Figure 2 illustrates Palo Alto’s actual and projected power supply mix for
2012 and 2018. (Note that 2012 was a slightly dry year, so the hydroelectric supply was a bit lower
than average. Also, about 1% of the overall hydro supply is RPSeligible “small hydro.”) If the City
8 The two other major sectors in the economy are the industrial and transportation sectors. In the Scoping Plan, CARB
estimates the industrial sector can reduce GHG emissions between 8% and 15%, while the transportation sector can reduce
GHG emissions between 27% and 32%. Much of the transportation sector’s emissions reduction burden is expected to be
shifted to the electricity sector via transportation electrification, which was not accounted for in CARB’s Scoping Plan. This
means the electricity sector’s GHG emissions reduction burden will be even greater than it appears.
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Section II: Background & Achievements to Date
10
renews its contract with the Western Area Power Administration after 2024, the 2030 power supply
mix is projected to be similar to the 2018 mix, but with less wind and landfill gas and more solar.
Figure 2: Palo Alto Power Supply in 2012 and 2018
Energy Efficiency iv.
California has continually increased the energy efficiency of its new buildings and appliances since the
Warren Alquist Act of 1974. These efficiency standards (Title 24) were updated to mandate Zero Net
Energy (ZNE) residential new construction starting in 2020. ZNE homes require energy efficiency that
will be achieved through implementing a highefficiency envelope (insulation, windows, etc.), and
efficient heating, ventilation, and air conditioning units. The remaining energy consumption must be
offset by onsite generation, sized so that the annual building electricity consumption is equal to the
building’s electricity generation. By 2030, staff anticipates that the CEC will incorporate a carbon metric
as part of the Title 24 building standards.
Overview of EIRP methodology D.
Integrated resource planning is the process that utilities undertake to determine a longterm plan to
ensure generation resources are adequate to meet projected future peak capacity and energy needs,
while achieving other utility goals such as maintaining an adequate capacity reserve margin for system
reliability. Resource plans must ensure generation reliability is maintained at or above industry
standard levels. IRPs should also forecast longterm costs and potential rate impacts to customers to
ensure that the utility can monitor and track trends with sufficient time to implement solutions to
ensure reliability, compliance, and affordable electric service. An effective resource plan should also
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Section II: Background & Achievements to Date
11
provide a reasonable degree of flexibility for the utility to deal with uncertainty in technological change
and future regulations.
IRPs require the use of sophisticated analytical tools capable of evaluating and comparing the costs and
benefits of a comprehensive set of alternative supply and demand resources. Supply options typically
include the evaluation of new conventional generation resources, renewable energy technologies, and
distributed energy resources. Demand options typically include consideration of demand response
programs, energy efficiency programs, and other “behind the meter” options which may reduce the
overall load that the utility must be prepared to supply.
IRPs utilize various economic analyses and methodologies to assess alternative scenarios (e.g.,
different combinations of supply and demand resources) and sensitivities to key assumptions to arrive
at an economically optimal resource plan (subject to various constraints, such as regulatory mandates
and local policies). The key steps in the resource planning process are outlined below.
Step 1: EXAMINE PLANNING FRAMEWORK AND RISKS: Identify and assess challenges the utility
faces in the current business and regulatory environment.
Step 2: ASSESS NEEDS: Develop forecasts of load changes (incorporating impacts of cost
effective demandside resources), existing plant conditions, contract terms, and operational
constraints to determine resource needs over the planning period.
Step 3: CONSIDER RESOURCE OPTIONS: Evaluate available generation resources, including
centralized and distributed renewables and longterm market power purchases to identify the
role each will play in meeting customer needs and regulatory and policy goals.
Step 4: DEVELOP RESOURCE PORTFOLIOS: Develop resource portfolios, and evaluate them
quantitatively and qualitatively to determine a preferred portfolio. Evaluation relies upon GHG
emission requirements, needs assessment, and planning data specified in previous steps.
Step 5: PERFORM SCENARIO AND RISK ANALYSIS: Perform detailed evaluations of preferred
resource portfolios through scenario and risk analysis, to assess performance under a range of
potential market and regulatory conditions.
Step 6: IDENTIFY PLAN: Identify a “Preferred Plan” based on the resource portfolio expected to
reliably serve demand at a reasonable longterm cost, while achieving regulatory compliance,
accounting for inherent risks, and allowing for flexibility to respond to future policy changes.
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Section III: Forecast Methodology for Energy and Peak Demand
12
Forecast Methodology for Energy and Peak Demand III.
Palo Alto’s forecasted energy and demand were generated by creating an econometric model for
monthly energy and peak demand and then combining them with separate forecasts for new
distributed energy resources (DERs) expected to be deployed. This approach was used since the
econometric models do not accurately capture new expected growth in these DERs. Separate models
were used to forecast DERs of highest impact. After energy and peak demand profiles for these DERs
were generated, these exogenous forecasts were then applied to the energy forecast as outofmodel
adjustments.
Equation 1: Methodology Energy and Peak Demand Forecast
8SXEP*SVIGEWX
! )GSRSQIXVMG*SVIGEWX2I[()6*SVIGEWXW
More details on the DER forecasts and load shape profiles that were generated are available in the
Proposed Distributed Energy Resources Plan, which was presented to the UAC in November 2017.
The DERs modeled for the purpose of this analysis were:
Energy Efficiency (EE)
Solar Photovolatics (PV)
Electric Vehicles (EV)
Demand Response (DR)
Energy Storage (ES)
Heatpump Water Heaters (HPWH)
Heatpump Space Heaters (HPSH)
The base case annual energy forecast is shown in Figure 3. The projected change in hourly load shape
on a peak day in 2030 is shown in Figure 4.
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Section III: Forecast Methodology for Energy and Peak Demand
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Figure 3: Annual Energy Forecast including DERs (20182030)
Figure 4: Impact of DERs on Hourly Summer Load Shape in 2030
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Section III: Forecast Methodology for Energy and Peak Demand
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Description of Econometric Forecast Models A.
The econometric model inputs (i.e. independent variables) have been selected based on the availability
of data, economic theory, and tests to validate the forecasts with actual energy (or demand) data. The
coefficients of the models were obtained via statistical estimation on historical (insample) data where
the YuleWalker Generalized Least Squares method was employed to take into account the
autocorrelation structure of the residuals so as to obtain valid standard error estimates. The
coefficients were then combined with forecasts of each driver (independent variable) to produce the
forecasted energy (or peak demand). Forecasts of the economic driver variable were provided by the
Bureau of Economic Analysis and the forecasted values provided by the UCLA Anderson Forecast
group. Weather variables were obtained from NOAA, and the forecasted weather conditions were set
to reflect normal weather based on average temperatures across the training data set.
Energy Econometric Modeli.
The Energy forecast is an econometric model that maps a set of calendar variables, weather variables,
and an economic driver variable onto Palo Alto’s monthly energy consumption measured at its
California Independent System Operator (CAISO) meter at the Palo Alto City Gate. The monthly
calendar variables are used in the model to capture underlying changes in Palo Alto customers’ electric
consumption caused by changing daylight hours and seasonal electricity usage. Monthly Heating
Degree Days and Cooling Degree Days are used to explain the variation in energy due to the weather.
Investment in nonresidential equipment and software as reported by the Bureau of Economic Analysis
was used as the economic driver. This variable represents business activity in the computer software
and equipment sector of the economy, which directly affects Palo Alto’s utility customers’ energy
consumption.
Peak Demand Econometric Model ii.
The Peak Demand forecast is also an econometric model that maps a set of calendar variables, weather
variables, and the energy forecast onto Palo Alto’s monthly peak demand measured at its CAISO meter.
Similar to the Energy Forecast, monthly dummy variables are used in the model to capture underlying
changes in Palo Alto customers’ electric consumption throughout the year. Daily heating and cooling
degree days corresponding to the peak day of the month is used as the weather driver. Monthly
historical energy usage is added as the final variable explaining peak demand.
Description of Distributed Energy Resources ForecastsB.
Distributed Energy Resource forecasts for a number of technologies were developed and presented to
the Palo Alto UAC in the proposed Distributed Energy Resources Plan in November 2017.
The distributed energy resources considered for the purposes of these analyses were:
Energy Efficiency (EE)
Solar Photovolatics (PV)
Electric Vehicles (EV)
Demand Response (DR)
Energy Storage (ES)
Heatpump Water Heaters (HPWH)
Heatpump Space Heaters (HPSH)
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DER penetration forecasts and load shape models were developed to address three main areas:
1.DER Adoption Projections: Adoption forecasts for each DER technology.
2.DER Load Impact Projections: Energy used or delivered to the system on an hourly and
seasonal basis to determine the impact of DERs on electric sales and load shape.
3.DER Financial Impact Projections: Financial impact to the utility of DER adoption based on the
adoption and load impact projections. This analysis considered only the impact to wholesale
electric supply costs, and did not include the impact of changes to current rate structures.
The detailed assumptions and limitations of each of these projections are discussed in their following
respective sections. The forecasts of the number of distributed energy resources in Palo Alto are
shown in Table 4. The impact that these DER systems will have on CPAU’s net electricity sales is shown
in Table 5, and previously in Figure 4.
Table 4: Projected Number of DER Systems (20172030)
Projected Number of Systems
DER Technology 2017 (current) 2020 2030
PV 1,000 1,300 2,500
EV9 2,500 5,900 18,700
EE 40,880 45,000 60,000
DR 8 25 75
ES 11 85 580
HPWH 10 200 2,700
Table 5: Projected Contribution to Energy Sales of DER Systems (20172030)
Contribution to Energy Sales 2017 (current)2020 2030
DER Technology MWh % MWh % MWh %
PV 15,000 1.6% 18,800 2.0%45,200 4.9%
EV 7,100 0.8% 14,300 1.6% 54,800 6.0%
EE 55,300 6.0% 78,800 8.6%139,200 15.2%
DR 7 23 200 0.02%
ES10
HPWH 9 190 0.02% 2,500 0.3%
HPSH 90 0.01%2,800 0.3%
9 This is the total number of residential EVs currently registered in Palo Alto. There are also EVs which commute into Palo
Alto, some of which charge while in Palo Alto and add to CPAU electricity sales. In addition to the residential EVs shown
here, there are estimated to be approximately 3,100, 5,900 and 20,000 commuter EVs in 2017, 2020 and 2030 respectively.
10 Batteries and other ES devices may result in either net increased energy retail sales (due to battery losses where
commercial customers use batteries to avoid CPAU demand charges) or net decreased energy retail sales (due to increased
onsite consumption of behind the meter solar). For the purpose of these analyses these two effects are assumed to be
roughly the same magnitude and therefore ES systems are not currently considered to have any net effect on energy sales.
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Section III: Forecast Methodology for Energy and Peak Demand
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Contribution to Energy Sales 2017 (current)2020 2030
DER Technology MWh % MWh % MWh %
Combined DER Impact: from
2007 63,200 6.9%83,000 9.1%124,000 13.6%
Combined DER Impact: from
2017 19,700 2.2%60,900 6.6%
CPAU Overall System Load
Growth from 201711 3,200 0.3% 6,900 0.8%
Energy Efficiency Forecast i.
a. Committed Energy Efficiency
AB 2021 (2006) required POUs to identify all potentially achievable costeffective electric efficiency
savings and to establish annual targets for energy efficiency savings over ten years, with the first set of
EE targets to be reported to the CEC by June 1, 2007, and updated every three years thereafter. AB
2227 (2012) amended this targetsetting schedule to every four years. Palo Alto adopted its first Ten
Year Energy Efficiency Portfolio Plan in April 2007, which included annual electric and gas efficiency
targets between 2008 and 2017, with a tenyear cumulative savings goal of 3.5% of forecasted energy
use. In accordance with California law, the electric efficiency targets were updated in 2010, with the
tenyear cumulative savings goal doubling to 7.2% between 2011 and 2020. Since then, increasingly
stringent statewide building code and appliance standards have resulted in substantial energy savings.
However, these “codes and standards” energy savings cannot be counted toward meeting the utility’s
EE goals. The tenyear electric efficiency targets were updated again in 2012, with the tenyear
cumulative electric efficiency savings being revised downwards to 4.8% between 2014 and 2023. For
fiscal year (FY) 2017, CPAU achieved electric savings of 0.7% of load through its customer efficiency
programs as shown in the most recent Demand Side Management Report. Cumulative electric
efficiency savings since 2006 are about 6% of the FY 2017 electric usage. Adoption rates for EE are
based on the 10year Energy Efficiency Goals for 20182027 which were updated in 2017. The tenyear
cumulative electric efficiency savings target was updated to 5.7% between 2018 and 2027. These
adopted goals are ambitious goals which include new programs in order to achieve a 20% increase over
the last goals adopted. For the years 2028 through 2030 the assumed savings are the average of the
savings in 2026 and 2027, which is the methodology suggested by the CEC for estimating savings
beyond the tenyear energy efficiency goals.12 More details on the EE methodology for market
potential can be found in Staff Report 7718 from March 6, 2017.
11 Going forward from 2017 the total CPAU load is forecasted to grow at roughly 0.4% per year if no more DERs were added
to the system. With the addition of new DERs, the total CPAU load is projected to decrease by roughly 0.8% from 2017
electricity sales by the year 2030.
12 The extension of savings through 2030 is based on the methodology put forth in the CEC presentation by Mike Jaske from
September 7, 2017, which can be found here: CEC presentation on Energy Efficiency Savings from Utility Programs.
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Section III: Forecast Methodology for Energy and Peak Demand
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Although CPAU established its EE goals based on net savings, the energy efficiency savings shown in
the tables and graphs here include EE savings due to freeridership as well as savings from statewide
codes and standards.
b. Additional Achievable Energy Efficiency
There is no additional achievable energy efficiency assumed in this EIRP forecast because the
additional achievable energy efficiency is already included in the ambitious adopted energy efficiency
goals for 2018 to 2027. These ambitious energy efficiency goals are 20% higher than a businessas
usual case and will require new innovative programs.
Solar Photovoltaic Forecast ii.
Solar PV projections are based on technical and economic potential; they indicate that adoption will
grow steadily, with the growth rate itself plateauing as is typically seen in a maturing market. These
projections include behindthemeter installations in residential and commercial sectors, but do not
include a potential Community Solar installation that has recently been discussed by the Palo Alto UAC.
In April 2014, the Palo Alto City Council approved the Local Solar Plan, which sets a communitywide
goal of meeting 4% of the City’s energy needs through local solar by 2023 and identifies a number of
strategies to help achieve that goal. These strategies include the development of several solar
programs to encourage installation of rooftop solar such as existing incentives like the feedin tariff
program and the PV Partners solar rebate program. As of the end of 2017 all solar installations within
the City generate 1.94% of the City’s electricity from about 10 MW of installed local solar capacity.
Transportation Electrification Forecast iii.
To date, Palo Alto has observed residential EV adoption rates approximately three times greater than
the California statewide average, and this residential adoption rate relative to statewide average
projections is assumed to continue to 2030. To estimate the EV adoption rates of commuters into Palo
Alto, the observed adoption rate from 2017 census data for the entire Bay Area was extended to 2030.
In addition to the number of residential EVs shown in Table 4 above, there are projected to be
approximately 3,100, 5,900, and 20,000 commuter EVs in 2017, 2020 and 2030, respectively.
Energy Storage Forecast iv.
This forecast is based on statewide projections for batteries and CPAU electricity rate structures. CPAU,
in coordination with the Palo Alto Development Services Department, is facilitating the adoption of
energy storage systems by customers by streamlining the process for permitting and interconnecting
such systems. Detailed analysis in 2017 showed that batteries are currently not cost effective within
CPAU’s service territory or at our remote renewable generation sites and therefore Palo Alto currently
does not provide any rebates for energy storage systems and is not currently planning to install storage
at any of our renewable resources. In August 2017, the Palo Alto City Council adopted a resolution
determining not to set a target for CPAU to procure energy storage systems at the wholesale level (or
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Section III: Forecast Methodology for Energy and Peak Demand
18
to establish a rebate program for behindthemeter installations) due to a current lack of costeffective
applications for Palo Alto. The City plans to revisit the analysis by 2020.13
Demand Response Forecast v.
CPAU has been running a voluntary summer demand response program for large commercial and
industrial customers since 2013, with an average of 45 DR events per year resulting in 0.51 MW of
peak load reduction. For the 2018 demand response program there are a total of 7 commercial
customers enrolled, with 525 kW of projected peak load reduction. The EIRP Energy and Peak Demand
forecasts are based on modest growth projections for the current voluntary large commercial demand
response program. Somewhat more robust growth is expected after the implementation of Palo Alto’s
Advanced Metering Infrastructure (AMI) program in 2023.
Electrification of Space and Water Heating Forecastvi.
The Energy and Peak Demand forecasts use historical solar PV penetration rates as a proxy for
adoption rates of heatpump water heaters and space heaters. Based on this analysis, staff projects a
natural gas load reduction of up to 1% from HPWH adoption, and an additional 1% load reduction from
HPSH adoption, by 2030.
SB 338 Requirements vii.
On September 30, 2017, SB 338 was signed into law by Governor Brown, including additional
provisions for the POU IRPs, which were effective January 1, 2018. This included revisions to Public
Utilities Code section 9621(c), requiring the POU’s governing board to “consider the role of existing
renewable generation, grid operational efficiencies, energy storage, and distributed energy resources,
including energy efficiency, in helping to ensure each utility meets energy needs and reliability needs in
hours to encompass the hour of peak demand of electricity, excluding demand met by variable
renewable generation directly connected to a California balancing authority, as defined in Section
399.12, while reducing the need for new electricity generation resources and new transmission
resources in achieving the state’s energy goals at the least cost to ratepayers.”
The development of this IRP began well in advance of the effective date of these provisions. However,
as part of the comprehensive process undertaken to develop this EIRP, the City reviewed and
considered resource options that included all of the technologically feasible and costeffective options
available to it, including what options would be best utilized to meet energy needs and reliability
requirements during hours of peak demand for the utility. This includes a review of the best available
options considering both new and existing preferred resources, as would necessarily be assessed in
order to ensure that Palo Alto provides its customers with the cleanest and most costeffective
generation resources, while also ensuring that the City meets all of the statutory requirements of not
only Section 9621, but other procurement and resources mandates, as well.
As previously mentioned, in November 2017 staff presented to the Palo Alto UAC an assessment of the
future impact of distributed energy resources (Distributed Energy Resources Plan). This assessment
13 The analysis that led to the City Council’s determination not to adopt a wholesale energy storage target can be found in
this report to the Palo Alto UAC: https://www.cityofpaloalto.org/civicax/filebank/documents/57435.
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Section III: Forecast Methodology for Energy and Peak Demand
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included guidelines for facilitating customer adoption as well forecasts of their potential to mitigate
peak demand for CPAU. The aggressive forecasts and programs for solar PV, energy efficiency, and
demand response have great potential to mitigate CPAU’s peak demand.
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Section IV: Existing Resource Portfolio
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Existing Resource Portfolio IV.
The City’s current electric supply portfolio comprises the following major types of resources:
Energy efficiency and distributed generation;
Federal hydro (Western contract);
Owned hydro (Calaveras);
Longterm, instate, RPSeligible power purchase agreements (PPAs), which include solar, wind,
and landfillgas resources; and
Market power purchases, matched with RECs, for monthly/hourly portfolio balancing.
For calendar year 2020, the projected contribution of each of these five resource types to the City’s
overall electric supply portfolio is represented in Figure 5 below.
Figure 5: Projected Palo Alto Electric Supply Mix in CY 2020 by Resource Type
* Estimated Average Annual Unit Cost of 6 ¢/kWh *
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Section IV: Existing Resource Portfolio
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Energy Efficiency & Local Renewable Generation A.
Energy Efficiency i.
Palo Alto has long recognized costeffective energy efficiency (EE) as the highest priority energy
resource, given that EE typically displaces relatively expensive electricity generation and lowers energy
bills for customers.
Palo Alto places such emphasis on energy efficiency and demand side management programs that each
year we prepare a detailed Demand Side Management Annual Report describing and reporting on
efficiency savings from electricity, gas, and water.
Highlights of Energy Efficiency Programs from 2017
Multifamily Residence Plus+ Program This program, which focuses on a hardtoreach
customer segment, was expanded in FY 2016 to include LED lighting measures, as the cost and
quality of LED lighting had improved. In September 2016, the contract with the vendor was
amended to add $500,000 to accommodate demand for the upgrades. As a result, the program
saw an increase in savings of over 950%.
The Home Efficiency Genie Program The Genie was launched in the summer of 2015 as a
home efficiency assessment program. The licensed energy auditors still do house calls, but the
program has expanded its focus to include more phonebased customer service on energy and
waterrelated topics. The Genie now provides information not only about efficiency but also
about the City’s sustainability programs, such as heat pump water heaters (HPWHs) and the
solar groupbuy program (SunShares). Staff also changed the program guidelines to allow the
Genie to discuss and advise residents on available rebates.
HeatPump Water Heater Pilot Program The goal of this program is reduction of greenhouse
gas (GHG) emissions through switching from natural gas appliances to highefficiency electric
appliances. Installation of heat pump water heaters (HPWHs) has been identified as a good
starting candidate for a pilot program. The pilot program—launched in the spring of 2016—was
designed to facilitate the installation of HPWHs in singlefamily homes. In April 2017, the City
hosted its first HPWH workshop to educate the community, including contractors, on the
technology and installation of HPWHs.
Green Building Ordinance – The Green Building Ordinance (GBO) is Palo Alto’s local building
reach code that is more stringent than the state Title 24 standard. This ordinance applies to
both residential and commercial buildings. CPAU previously assisted in the development of this
code, but FY 2017 is the first year for which savings associated with the GBO have been
reported in this report.
Building Operators Certification (BOC) Course CPAU hosted a Building Operators Certification
Course taught by Northwest Energy Efficiency Commission (NEEC) from Seattle. BOC is an eight
class certification course covering all aspects of building management and efficiency. Some
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Section IV: Existing Resource Portfolio
22
topics covered were: HVAC, electrical systems, comfort control and lighting. Upon passing an
endofclass exam, graduates could become Certified Building Operators (CBOs).
Residential Energy Assistance Program (REAP) This program provides qualifying lowincome
residents with free energy efficiency measures and access to the Rate Assistance Program (RAP)
rate discount. For qualifying customers, a Home Assessment, an application to the RAP, and an
onsite customer evaluation for weatherization and energy efficiency measure installation,
including insulation and lighting, is provided. Customers may have refrigerators and/or furnaces
replaced if the need is found.
Local Renewable Generation ii.
Local renewable energy programs are critical to lowering emissions of local air pollutants and CPAU has
enacted a number of initiatives and programs to facilitate customer adoption. In addition, in 2014 the
Palo Alto City Council adopted the Local Solar Plan with the goal of having local solar photovoltaic
facilities provide 4% of the City’s total energy needs by 2023.
The following is a description of Palo Alto’s current customerside renewable generation programs:
Solar PV Groupbuy Every year since 2015 Palo Alto has been an active partner in promoting
the Bay Area SunShares PV Groupbuy program which prescreens solar installers and
negotiates lower rates for customers. In both 2015 and 2017 Palo Alto was the top “Outreach
Partner,” both in terms of the number of solar contracts signed and the kilowatts of rooftop
solar capacity that will be installed through the program. From 2015 to 2017 Palo Alto residents
have signed 88 solar contracts through the SunShares PV Groupbuy program for a total of 421
kW of installed rooftop solar capacity.
PV Partners The PV Partners Program encourages photovoltaic or solar electric (PV)
installations on Palo Alto homes and businesses by providing a rebate based on the capacity,
measured in watts, of newly installed PV systems. The PV Partners Program continues to be one
of the most successful in the State. Rebate funds were fully reserved in April 2016. The effect of
the PV Partners program can be seen in the cumulative total of PV installations. As of June 30,
2017, there were 1,003 PV installations with the total capacity of 8.617 MW (5.04% of Palo
Alto’s system peak load).
NetEnergy Metering Successor Program Prior to January 1, 2018 residential and commercial
customers in Palo Alto who installed approved PV systems were able to sign up for the CPAU
Net Energy Metering (NEM) program. CPAU reached the NEM cap of 10.8 MW in January 2018
and CPAU is now offering a NEM Successor Program instead. The NEM Successor process is
integrated with the permitting process, and customers receive a credit for electricity exported
to the grid based on CPAU’s avoided costs.
Palo Alto CLEAN (Clean Local Energy Accessible Now)This feedin tariff program purchases
electricity generated by renewable energy resources located in Palo Alto’s service territory and
interconnected on the utilityside of the electric meter. The electricity is purchased by Palo Alto
for the electric renewable portfolio standard. The program was launched in 2012 and has been
modified over the past few years. On February 3, 2014 the Palo Alto City Council approved a
total program capacity of 3 MW at a price of 16.5 cents per kilowatt hour (kWh) fixed for 20
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Section IV: Existing Resource Portfolio
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years. On May 8, 2017 the Palo Alto City Council approved minor changes to Palo Alto CLEAN.
The program no longer has a total participation cap for either solar or nonsolar eligible
renewable energy resources. CPAU is currently offering to purchase the output of eligible
renewable electric generation systems located in Palo Alto at the following prices:
o For solar energy resources: 16.5 cents per kilowatt hour (¢/kWh) for a 15, 20or 25
year contract term until the subscribed capacity reaches 3 MW – after that the price will
drop to 8.8 ¢/kWh for a 15year contract term, 8.9 ¢/kWh for a 20year contract term,
or 9.1 ¢/kWh for a 25year contract term; and
o For nonsolar eligible renewable energy resources: 8.3 ¢/kWh for a 15year contract
term, 8.4 ¢/kWh for a 20year contract term, or 8.5 ¢/kWh for a 25year contract term.
There is no minimum or maximum project size, but the program is best suited for commercial
property owners with available rooftops or parking lots. Palo Alto’s Public Works Department
recently solicited proposals to install solar PV systems and electric vehicle chargers at four City
owned parking structures. All four of these parking garage solar PV systems are operational as
of March 2018. As of August 2018, there are a total of six solar PV systems participating in the
Palo Alto CLEAN program, including the four aforementioned systems on Cityowned parking
garages. These six projects account for 2.915 MW of the capacity available at the 16.5 ¢/kWh
contract rate, with contract terms ranging from 15 to 25years; five of them projects are now
operational, and the sixth is expected to be online by the end of 2018.
Hydroelectric Resources B.
Western Base Resource i.
Since the 1960s, CPAU’s participation as a power customer of the Central Valley Project (CVP) has been
an instrumental factor in its ability to deliver lowcarbon electricity to Palo Altans at low rates. The U.S.
Bureau of Reclamation (BOR) built the CVP in the 1930s and is charged with the operation,
maintenance, and stewardship of the project. The CVP was constructed primarily for flood control of
the Sacramento Valley area; however, it is also used to provide water for irrigation and municipal use
and for navigation and recreational purposes. Hydroelectric generation is a lower priority function of
the CVP, relative to the aforementioned purposes.
The BOR is legally required to first provide power to “Project Use” for operations and pumping water
through the CVP project, and then to “First Preference Customers,” those customers whose livelihood
and/or property/land was impacted by the construction of the CVP. The remaining hydroelectricity
(“Base Resource”) is then made available for marketing under longterm contracts with notforprofit
entities such as municipal utilities and special districts. The Western Area Power Administration
(WAPA) is the federal Power Marketing Agency charged with marketing and contracting with
customers for the electric output associated with the CVP, and collecting funds to meet allocated
revenue requirements on behalf of the BOR.
In 2000, the City executed a new 20year contract with WAPA for CVP power deliveries starting in
2005. Under this contract the City receives 12.3% of all the Base Resource product output and is
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obligated to pay 12.3% of all the CVP’s revenue requirements as allocated to power customers,
regardless of the amount of energy received. Under normal precipitation and hydrological conditions,
this resource provides nearly 40% of CPAU’s electricity needs. However, since 2005 the amount has
varied from a low of 22% to a high of 64%. The corresponding cost per MWh has ranged from $22 to
$61/MWh.
The current Base Resource contract is set to expire at the end of 2024. Western’s proposed 2025
Power Marketing Plan, submitted to the United States Federal Register Notification (U.S. FRN No
27433), if approved by the Department of Energy, would allow existing Base Resource power
customers to renew up to 98% of their existing allocation for a thirtyyear term (20252054) under
similar contract terms and conditions to their existing contracts.
The process for extending this contract is well underway and is expected to take five to seven years to
complete (Western's 2025 Power Marketing Plan Tentative Schedule). CPAU staff has been actively
involved in the process by providing informal and formal comments in response to the 2025 Western
Power Marketing Plan and by working with WAPA staff and other Base Resource contract customers to
develop a better model of longterm generation and cost projections. Pending approval of the 2025
Power Marketing Plan, Western will seek commitments through execution of the new Base Resource
contract in 2020 – although participants are expected to have an option to reduce participation and/or
terminate their contract in 2024.
A key topic for consideration in the EIRP is whether or not the City should renew its Base Resource
contract – and if so, at what level. The analysis necessary to aid Council in its decision will need to
consider the cost and the value of the resource going forward, which are both highly uncertain. This is
due in large part to the nature of the CVP and supply availability, which is dependent on unpredictable
precipitation conditions, the longterm effects of climate change, and the potential for new
environmental policies and/or projects which threaten to erode generation value.
The costs associated with participating in the Base Resource are also highly uncertain. First, the BOR
has yet to update the cost allocation study necessary to establish rates for CVP power under the
existing contract, and it is unclear when such rates will be published for the post2024 period.
Additionally, funding requirements under the Central Valley Project Improvement Act (CVPIA)14 and
the appropriateness of the allocation of Restoration Fund collections between water and power
customers is of serious concern to CPAU and other power customers, who have been actively
encouraging BOR and Congress to adjust this allocation.
Lastly, the potential for changes to local and state RPS requirements – such as portfolio mandates or
carveouts for baseload renewables and/or not providing consideration for supply variability associated
with large hydroelectric resources – as well as the potential for loss of load due to distributed energy
resources or load defection, increase the risk of a renewed Base Resource contract becoming a
14 The Central Valley Project Improvement Act was passed by the U.S. Congress in 1992 to establish the Restoration Fund,
funding requirements and goals to restore the habitat of the area impacted by the CVP. Water and power customers are
obligated to pay into the Restoration Fund. https://www.usbr.gov/mp/cvpia/docs/publiclaw102575.pdf
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stranded resource, unless clear and reasonable termination provisions are included in the new
contract.
NCPA staff and CPAU staff are in the process of assessing the impact magnitude and likelihood of
several issues which threaten to dilute the future value of Base Resource, as well as NCPA’s and CPAU’s
ability to influence these issues. These issues are in addition to highly variable hydrological and
precipitation conditions which create yeartoyear variations in value. Staff and NCPA will work
towards refining the analysis of these risk factors, to aid in the decision of how much Base Resource to
renew for the post2024 period.
Calaveras ii.
Calaveras was bondfunded and built as a joint project between members15 of the Northern California
Power Agency (NCPA) and the Calaveras County Water District (CCWD) in 1983. CCWD holds the
Federal Energy Regulatory Commission (FERC) license and NCPA is the project operator. The project
resides on the North Fork of the Stanislaus River in Calaveras, Alpine and Tuolumne Counties. Calaveras
was built primarily for hydroelectric generation purposes and as such water is stored and managed to
optimize generation value and to meet member owners’ energy needs. Palo Alto’s share in the project
is 22.92%, which serves approximately 14% of the City’s annual load in an average hydro year.
Calaveras’ project capacity is about 253 MW and can generate 575 gigawatthours (GWh) of energy
annually under average hydroelectric conditions. Palo Alto’s corresponding share of the output is 58
MW of capacity and 132 GWh of annual energy.
As of January 2019, the City’s outstanding debt on the project is approximately $89 million, of which a
large portion will be maturing in 2024 and the remainder will mature in 2032. Annually through fiscal
year 2024, the City’s debt related to this project is on average about $9 million. For the remaining years
until 2032, the debt is about $5 million. Historically, debt and other costs associated with Calaveras
have resulted in the overall value of the project being below market.16 For FY 2018, Palo Alto’s share of
the project cost, including debt, is $12.5 million and the value is expected to be $5.7 million, resulting
in a net cost of $6.8 million. However, because Calaveras’ variable operating and maintenance costs
are relatively low, the project is dispatched regularly for the purpose of generating energy.
Additionally, Calaveras has the ability to meet several CAISO compliance and operating requirements,
including: following variations in the City’s load in realtime (load following), ancillary services related
to regulation energy and spinning reserves; and meeting some of the City’s Resource Adequacy
15 NCPA members participating in the Calaveras Project via the Calaveras Third Phase Agreement with NCPA include the
cities of Alameda, Biggs, Gridley, Healdsburg, Lodi, Lompoc, Palo Alto, Roseville, Santa Clara, and Ukiah, and the Plumas
Sierra Rural Electric Cooperative.
16 In anticipation of Direct Access and the possibility for load to leave CPAU, in 1996 Council approved a competitive
transitioncharge (CTC) to be added as a nonbypassable fee on all CPAU customers electricity bills. This was done to collect
the above market cost (stranded cost) associated with Calaveras debt and the funds were held in the Calaveras Reserve,
which had been established in 1983 to help defray cost associated with Calaveras. The Calaveras Reserve was repurposed in
2011 and is now the Electric Special Project Reserve (see Staff Report 2160).
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requirements, including flexible capacity and system capacity. Calaveras also serves as an energy
storage asset, since water is stored in the main reservoir, New Spicer Meadow, and released at optimal
times to meet energy and capacity needs. Longterm it is expected that the value of Calaveras will
increase, assuming average or above average hydroelectric conditions and favorable regulatory
requirements.
While there are no imminent decisions associated with Calaveras, a few issues may be worth
evaluating in the context of the EIRP, including:
1. Assessment of Calaveras value and operating strategies, given the City’s commitment to other
large hydroelectric resources, RPS resources, and hydro risk management objectives;
2. How to best optimize Calaveras given its potential value to meet intermittent resource
integration requirements; and
3. The value of the City’s longterm stake in Calaveras, including the post2032 period, when the
current FERC license expires.
Renewable Energy Resources C.
Wind PPAs i.
Palo Alto currently has two longterm contracts for the output of wind power projects. Under separate
contracts with Avangrid Renewables (formerly Iberdrola Renewables), the City receives a 25 MW share
of the output of the Shiloh I project, and a 20 MW share of the output of the High Winds I project in
Solano County, both of which are located in Solano County. The terms of these two contracts end in
2021 and 2028, respectively. Together, the two resources typically supply about 12% of Palo Alto’s
total electric supply needs. Both projects are considered fully deliverable, and are located in the Bay
Area local reliability area.
Landfill Gas (LFG) PPAs ii.
Palo Alto currently has five longterm contracts with Ameresco for the output of landfill gas electricity
projects. The five contracts include a 1.5 MW share of a project located in Watsonville, a 5.1 MW share
of a project located in Half Moon Bay, a 1.9 MW share of a project located in Pittsburg, and the entire
output of a 1.4 MW project located in Gonzales and a 4.1 MW project located in Linden. The terms of
these agreements are all 20 years, with contract expiration dates between 2025 and 2034. Together,
the five resources currently supply about 11% of Palo Alto’s total electric supply needs. All five projects
are also considered fully deliverable, with two of them located in the Bay Area local capacity area.
Solar PPAsiii.
Since the beginning of 2012, Palo Alto has executed six longterm contracts for utilityscale solar PV
projects. These six contracts include three with sPower (the 26.7 MW Hayworth Solar project located
in Bakersfield, and the 20 MW Western Antelope Blue Sky Ranch B project and the 40 MW Elevation
Solar C project –MW EE Kettleman
Land project in Kettleman City and the 20 MW Frontier Solar project located in Newman), and one with
Hecate Energy (the 26 MW Wilsona Solar project, which is slated to be built near Palmdale). The first
five of these projects are currently operational, and they provide roughly 33% of Palo Alto’s total
electricity needs; meanwhile, the Wilsona project is scheduled to begin energy deliveries in mid2021.
The terms of these agreements are all at least 25 years, with contract expiration dates starting in 2040.
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The three projects operated by sPower are considered fully deliverable, with the Hayworth project
located in the Kern local capacity area, and the other two located in the Big CreekVentura local
capacity area.
Market Purchases & RECs D.
Palo Alto has nine active Master Agreements (with BP Energy, Shell Energy North America, Powerex
Corp, Cargill Power Markets, Exelon Generation, Iberdrola Renewables, NextEra Energy Power
Marketing, Turlock Irrigation District, and PacifiCorp) to facilitate competitive forward market
purchases and sales to meet Palo Alto’s loads in the short to mediumterm. As of June 30, 2018, Palo
Alto had outstanding electricity purchase commitments for the period July 2018 to June 2020 totaling
79 GWh, and sales commitments for this period totaling 161 GWh. These market based purchases and
sales are made within the parameters of Palo Alto’s Energy Risk Management Program.
In FY 2018, gross marketbased purchases (including both forward transactions and spotmarket
transactions) provided approximately 14% of Palo Alto’s electricity needs, while gross marketbased
sales were equivalent to 23% of Palo Alto's needs (i.e., the City was a net seller of marketbased
energy). The volume of market purchases and sales however is highly dependent on hydro conditions
and longterm commitments to renewable resourcebased supplies. During normal hydro conditions,
gross market purchases are expected to meet approximately 15% of energy needs, while gross market
sales will amount to approximately 25% of energy needs. NCPA serves as Palo Alto’s scheduling and
billing agent for all transactions, and acts as the interface with the CAISO under a Metered Subsystem
Aggregation Agreement (MSSA).
Since 2013, Palo Alto has operated under a Carbon Neutral Plan for its electric supply portfolio,
ensuring that all electrical generation that serves the City’s needs produces zero GHG emissions on a
net annual basis. To implement the Carbon Neutral Plan, in years when the City has been a net
purchaser of market power (e.g., in very dry hydro years, or before the City’s longterm solar contracts
had started delivering power to Palo Alto), it has purchased Renewable Energy Certificates (RECs) in
volumes equivalent to its net market power purchase volumes.
COBUG E.
In 2002, shortly after experiencing a series of rolling blackouts during the California energy crisis, the
City decided to invest in a set of locallysited natural gasfired backup generators in order to stave off
such events in the future. These four generators, together known as the Cooperatively Owned BackUp
Generator (COBUG), total 5 MW in capacity but are seldom operated (generally only for maintenance
purposes). They do, however, serve as an important source of local system reliability in the Bay Area
local capacity area.
CaliforniaOregon Transmission Project (COTP) F.
Fourteen Northern California cities and districts and one rural electric cooperative, including Palo Alto,
are members or associate members of a California joint powers agency known as the Transmission
Agency of Northern California (TANC). TANC, together with the City of Redding, WAPA, two California
water districts, and Pacific Gas and Electric (PG&E) own the CaliforniaOregon Transmission Project
(COTP), a 339mile long, 1,600 MW, 500 kV transmission power project between Southern Oregon and
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Central California. Palo Alto is entitled to 4.0% of TANC's share of COTP transfer capability (50 MW). As
a result of low utilization of the transmission capacity and therefore low value relative to costs (in
addition to a focus on acquiring instate renewable resources), in August 2008 Palo Alto effected a
longterm assignment of its full share and obligations in COTP to the Sacramento Municipal Utility
District (SMUD), Turlock Irrigation District (TID), and Modesto Irrigation District (MID). The longterm
assignment is for 15 years (through 2023), with an option to extend the assignment for an additional
five years.
Resource Adequacy CapacityG.
As described above, the majority of Palo Alto’s longterm generation contracts (and its one owned
thermal generating asset) are deemed fully deliverable and provide the City with Resource Adequacy
(RA) capacity to satisfy its CAISO regulatory requirements. The amounts of RA capacity provided by
each resource are detailed in the CRAT standardized table in the appendices of this report, and a high
level overview is provided in Table 6 below.
Table 6: Palo Alto’s Resource Adequacy Capacity Portfolio
Project Resource Type Local Area Flexible RA?Average NQC (MW)
Western Base Resource Hydroelectric CAISO System No 147.0
Calaveras Hydroelectric CAISO System Yes 58.0
High Winds Wind Bay Area No 4.5
Shiloh I Wind Bay Area No 5.7
Santa Cruz LFG Landfill Gas CAISO System No 1.5
Ox Mountain LFG Landfill Gas Bay Area No 5.1
Keller Canyon LFG Landfill Gas Bay Area No 1.9
Johnson Canyon LFG Landfill Gas CAISO System No 1.4
San Joaquin LFG Landfill Gas CAISO System No 4.1
Hayworth Solar Solar PV Kern No 14.2
Elevation Solar C Solar PV Big CreekVentura No 21.9
Western Antelope Solar PV Big CreekVentura No 11.0
COBUG Natural Gas Bay Area No 4.5
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Future Procurement Needs and Portfolio Rebalancing V.
Needs Assessment: Energy, RPS, Resource Adequacy Capacity A.
Overall, Palo Alto’s resource portfolio has a surplus of energy, and a surplus of RPS generation (relative
to its RPS procurement requirements under SB 350), as detailed in the Standardized Tables presented
in Appendix D. Figure 6 below depicts the City’s projected supplies17 of eligible renewable generation
for the period 2003 to 2038, as well as the City’s annual RPS generation procurement requirements
under SB 350, based on its actual and forecasted retail sales volumes. Note that this figure presents
only currently contracted resources; no additional resources are assumed to be procured, and no
existing contracts are assumed to be extended.
Figure 6: Palo Alto’s RPS Generation Projections and RPS Compliance Requirements
In terms of capacity, the City has a surplus of system RA capacity, but deficit positions in local and
flexible RA capacity.18 The City makes up these deficits each year via bilateral RA capacity purchases.
One of the challenges that CPAU faces over the IRP planning period is ensuring that it can continue to
17 Note that renewable energy supplies shown in Figure xx which are surplus to the City’s RPS procurement requirements
may ultimately be sold or banked for use in future compliance periods.
18 For additional details on Palo Alto’s projected needs and supplies of electrical generation, RPS generation, and RA
capacity, please see the EBT, RPT, and CRAT standardized tables in Appendix D to this report.
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procure adequate supplies of local and flexible RA capacity – both to satisfy its regulatory compliance
obligations, and to ensure the overall reliability of the CAISO bulk transmission system.19
However, during the IRP planning period, CPAU staff’s primary focus will be on determining whether to
renew its Western Base Resource contract for a new 30year term starting in 2025 – and if so, at what
capacity share. As such, staff will be heavily focused on negotiating contract terms that provide the City
with protection and flexibility, while also closely monitoring the many issues that are currently creating
uncertainty around this resource’s longterm costs and generation levels. The remainder of this section
of the EIRP will focus on exactly this question: whether to renew the Western Base Resource contract
at the maximum possible level, or whether to “rebalance” the City’s electric supply portfolio by scaling
back (or eliminating) the City’s Base Resource allocation and replacing it with a different generation
resource.
Portfolio Rebalancing Analysis B.
As noted in the September 2017 report to the Palo Alto UAC, CPAU staff evaluated a very large number
of potential new supplyside and demandside resources in the portfolio analysis it performed related
to the Western Base Resource contract renewal decision. However, as the analysis progressed, due to
reasons of feasibility/availability and cost/uncertainty, staff narrowed the focus of the analysis to the
following resources:
A renewed Western Base Resource (Western) contract,
Instate solar,
Outofstate wind,
Geothermal,
Local (Palo Alto) solar, and
Market power purchases matched with renewable energy certificates (RECs).
The Western hydro resource and instate solar resource characteristics are well understood, given the
large role they each play in Palo Alto’s current resource portfolio. Western is a relatively lowcost,
flexible resource – at least in average years – but it features a large amount of seasonal variability, as
well as yeartoyear uncertainty around its cost and level of output. In addition, there are several major
issues currently pending that have the potential to significantly impact the cost and/or operation of the
resource.20 Solar also involves a great deal of seasonal variability and contributes towards the seasonal
19 Also, if Palo Alto opts not to renew its Western Base Resource contract in 2025 – or significantly scales back its share of
this resource – then the City will face the additional challenge of ensuring it has adequate system RA capacity to meet its
planning reserve margin requirements. As Table 6 indicates, the Western Base Resource contract is by far the City’s largest
source of system RA capacity.
20 For example: The State Water Resources Control Board has several proceedings underway that may have very significant
impacts on Western operations, including the consideration of an “unimpaired flow” criteria as part of its Bay Delta Plan
that could result in significantly less generation from Western, particularly in the summer months. There are also longterm
risks associated with an increase in “Aid to Irrigation” payments that Power customers may be required to make to Water
customers, litigation related to the Central Valley Project Improvement Act (CVPIA) Restoration Fund payments that Power
customers make, potential cost impacts to Power customers related to the “Twin Tunnels” project, and the impacts of
climate change on the resource. Staff hopes that many of these uncertainties will be better understood by 2024; however it
is likely that a number of them will remain unresolved. These risks must be more closely examined before making a final
contract commitment in 2024.
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imbalance of the supply portfolio, but with far less uncertainty around its cost or annual output
amount. And while its costs have decreased dramatically in recent years, the huge volume of recent
capacity additions – which have been concentrated in areas with the best solar potential – have driven
down the market value of this energy at least as much, leading to a sharp increase in negative market
prices and curtailments. The rise of solar generation in the state has also led to the Duck Curve
phenomenon21, which has in turn resulted in new regulatory requirements for each loadserving entity
(LSE) to procure sufficient flexible generation capacity to maintain transmission grid reliability.
Outofstate wind resources – e.g., from the Pacific Northwest or New Mexico – have also become very
lowcost in recent years, in some cases even lower priced than solar.22 Wind resources from these
areas typically have a generation profile that is a good fit for the City’s portfolio, producing somewhat
more energy in the fall and winter months than in the spring and summer months. However, the cost
of obtaining transmission access for them into the state significantly raises their total cost.23
Geothermal resources have also experienced a price decline in recent years, although they are still less
valuable compared with solar or outofstate wind. New binary cycle geothermal technology also
produces no GHG emissions and can be more flexibly dispatched compared to prior generations of
geothermal technologies. This technology bears further consideration in the coming years as the City
considers options to rebalance the portfolio.
Local solar is the only local supply resource considered in the portfolio analysis. While it would have a
higher value than solar located in the central San Joaquin Valley24 it is unlikely to be available in
sufficient quantities to make a significant contribution to the City’s overall electric supply needs. The
cost of such local systems would also be relatively high. For example, under the Palo Alto CLEAN
program, even with a contract price of 16.5 cents/kWh, the program existed for several years before
finally securing about 3 MW of participating capacity within the last two years. And the cost of solar
energy from a 500 kW project at the Palo Alto golf course was estimated at 10 to 14 cents/kWh in
21 The Duck Curve refers to the graph shown in Figure 1, illustrating the impact of the increasing adoption of solar PV on
CAISO’s net load (i.e., total load less generation from variable energy resources like wind and solar). Over time, as more
solar generation came online, the CAISO net load curve went from having a slight midday peak to having a deep midday
trough, bracketed by a steep downward ramp in the morning, as solar plants begins generating, and an even steeper
upward ramp in the evening, as solar generation trails off with the sunset. For more information, see:
https://www.caiso.com/documents/flexibleresourceshelprenewables_fastfacts.pdf.
22 Staff has received numerous proposals for outofstate wind resources over the past several years, but such resources
were found to be uneconomical compared to instate solar when Palo Alto made longterm commitments for solar
resources between 2012 and 2016.
23 The availability of transmission pathways to bring this generation into CAISO on a reliable basis is also not assured.
However, for Pacific Northwest wind resources, the City’s allocation of capacity on the CaliforniaOregon Transmission
Project (COTP) could prove very useful. The City laid off this transmission capacity for a 15year period, but this layoff will
end at the end of 2023.
24 Local solar is currently at least 3 ¢/kWh more valuable than remote solar, given that it would provide enhanced local
resiliency, would not be subject to transmission charges, would reduce the City’s resource adequacy capacity requirements,
and would have a high locational value, due to its mitigating effect on Bay Area transmission congestion.
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2017, which is more costly compared to other resource options, even with the greater value (primarily
due to avoided transmission charges) inherent in local generation.
Finally, market energy purchases combined with unbundled RECs could present an attractive option in
the shortterm if the City wishes to reduce its Western contract allocation and seek a different lowcost
solution. In the longterm, however, many forecasts indicate that as the state’s GHG reduction
requirements ratchet up, the cost of carbon allowances will likewise climb, which in turn would raise
market power prices and make this option uneconomic. In addition, this approach would perpetuate
the City’s reliance on traditional GHGemitting generators. On the other hand, shorterterm market
purchases would provide the City with a great deal of flexibility in terms of contract duration and
volume, and lower the risk of stranded energy resources if the electric loads available to be served by
the City decline significantly.
Table 7 below summarizes the various resource types that staff considered most closely in its portfolio
analysis and their relative merits. The key indicators used for comparing the different portfolio options
are:
Value: The net value of a resource; the projected revenue from selling the resource’s energy
into the CAISO market less the resource’s bilateral contract cost;
Portfolio Fit: Lower reliance on the grid for hourly load balancing;
Diversification: Geographic and resource diversity;
Term Flexibility: Flexibility in length of contract and termination provisions; and
Cost Certainty: Degree of certainty of future resource costs.
Table 7: Relative Merits of Candidate Resources Considered to Rebalance Supply Portfolio
* Ratings reflect relative changes from current portfolio of resources *
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Portfolio Expected Net Value i.
First, as far as the net value of a resource contract for the 2025 to 2030 period, Western has the
potential to be a relatively valuable resource, but also has the most uncertainty when it comes to
costs, for the reasons described above. The expected net value of Western and several potential new
contracts, as determined by a scenariobased spreadsheet analysis, is shown in Figure 7. The net value
of each resource is calculated based on its energy values (from each resource’s LMP forecast), along
with the ancillary services value provided by Western, the value of the RECs generated by the
renewable resources, and each resource’s RA capacity. Note that the expected net value of some
resources is negative (less valuable than projected market value), due to the fact that the cost of all of
the renewable resources includes the cost of renewable attributes in addition to energy, and because a
primary goal of a longterm agreement such as a PPA is to hedge and manage exposure to future price
volatility.
Figure 7: Expected Net Value of New Resources and Western Relative to Market Value
* Very High Cost Uncertainty around Western *
One of the primary messages of Figure 7 is that there is a tremendous amount of uncertainty around
the net value of Western, as indicated by the large uncertainty bars featured on that data series.25 It
should be noted that the uncertainty shown in Figure 7 is based on staff’s best estimate of the
25 Figure C6 does not include market price uncertainty or hydrological uncertainty; the uncertainty range shown for
Western represents purely regulatory and litigationrelated cost uncertainty.
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Section V: Future Procurement Needs and Portfolio Rebalancing
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potential range of future Western contract costs. It should also be noted that this uncertainty is heavily
biased toward the negative direction: there is limited “upside” uncertainty while there is a great deal
of “downside” uncertainty, largely related to pending environmental regulatory issues.
Portfolio Fit ii.
Another key indicator is hourly portfolio fit, which will determine how reliant the portfolio is on grid
power (and, as a result, how exposed it is to market prices). Figure 8 displays average hourly
generation profiles for each month (one average day per month is shown) for Western and other
potential new resources relative to the City’s average load. Although total resource supplies from long
term contracts exceed the City’s load in the spring and summer months, the opposite is true during the
fall and winter months. Thus Figure 8 indicates that outofstate wind, which produces more energy in
the fall and winter months, would be a good complement to the City’s existing portfolio. Instate wind
(in the Solano hills) and solar, on the other hand, exacerbate the City’s portfolio fit problem, as they
produce more energy in the spring and summer months.
Figure 8: Average Hourly Load and Generation Profiles for Each Month for Western and Potential
New Resources (Normalized to Average Hourly Load)
* New Mexico Wind Resource Profile Complements Palo Alto Portfolio *
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Portfolio Cost Uncertainty and Managementiii.
The cost uncertainty of the electric supply portfolio in the shortterm is primarily driven by the water
available for hydroelectric production, and is estimated at $10 to $15 million per year at prevailing
market prices. Palo Alto is well positioned to manage this cost uncertainty through its hydro rate
adjustment mechanism26 and by maintaining sufficient cash reserves. The cost uncertainty related to
seasonally balancing the portfolio27 is minimal since market price variability between seasons is highly
correlated and because staff executes seasonal buysell transactions at the same time.
As noted above, in the longterm, there are a number of issues that could dramatically affect the value
of the Western resource in the coming years. As such, a large focus of staff efforts in the next five years
will be to better understand the longterm economics of the Western resource and mitigate the risks
associated with it through flexible contractual terms.
There are also proceedings underway to investigate market restructuring to deal with issues related to
the integration of variable renewable resources, such as overgeneration, very steep evening ramp
periods, and the appropriate valuation of dispatchable generation capacity. Volatility in market prices,
as the CAISO and the CEC determine how to send price signals to ensure a reliable grid, could leave a
seasonally unbalanced portfolio such as the City’s current portfolio exposed. Increases in transmission
charges could also make remote resources compare less favorably to local resources and demandside
management in the future.
26 For additional detail on the hydro rate adjustment mechanism, please see Staff Report ID 8962 (March 2018):
https://www.cityofpaloalto.org/civicax/filebank/documents/63851.
27 Revenues received from the sale of surplus energy during the spring and summer periods are utilized to purchase
electricity needs for the fall and winter periods.
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Section IV: Supply Costs & Retail Rates
36
Supply Costs & Retail Rates VI.
Critical to the success of an IRP, in addition to ensuring that the adopted plan leads to compliance with
all regulatory requirements, is ensuring that it also results in supply cost minimization and (ideally) low
and stable customer retail rates. As described in the FY 2019 Electric Utility Financial Plan and Rate
Proposal to the Palo Alto City Council, CPAU staff projects supply costs to rise substantially for the next
several years, largely driven by increases in transmission costs and new renewable energy projects
coming online. Retail rates are also projected to rise due to substantial additional capital investment in
the electric distribution system, and operational cost increases.
In order to ensure adequate revenue recovery, the Palo Alto City Council recently approved a 6% retail
rate increase for FY 2019 (taking effect July 1, 2018), and adopted a Financial Plan that calls for an
additional 3% rate increase for FY 2020 with 02% annual rate increases projected thereafter. However,
it should be noted that the City’s current electric rates are far lower than the statewide average
electric retail rates, and, under the recommended portfolio presented in Section X of this report, staff
projects that they will remain so. In fact, even under the worstcase scenarios staff evaluated the
recommended portfolio against, as described in Section X.C of this report, the City’s retail electric rates
remain lower than the projected statewide average rates.
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Section VII: Transmission & Distribution Systems
37
Transmission & Distribution Systems VII.
Transmission System A.
At the transmission level, CPAU staff has two main focuses during the EIRP planning period: (1)
determining the optimal utilization of the COTP asset when Palo Alto’s longterm layoff of this resource
ends on January 1, 2024, as discussed above in the Existing Resource Portfolio section; and (2) pursuing
an additional interconnection point with PG&E’s transmission system. The new interconnection point
with PG&E is being sought in order to provide redundancy, and therefore increased local reliability, in
the event that an outage affects the three current interconnection lines – as happened in February
2010.28 To minimize the possibility of a Citywide outage caused by an interconnection line outage, it is
in the City’s interest to find a physically diverse connection to the PG&E transmission system for power
supply to the City. Staff has been investigating options for an alternative connection to the
transmission grid for numerous years.29
Distribution System B.
Palo Alto’s electric distribution system is directly interconnected with the transmission system of
Pacific Gas and Electric Company (PG&E) by three 115 kV lines, which have a delivery point at Palo
Alto’s Colorado substation. Palo Alto’s distribution system consists of the 115 kV to 60 kV delivery
point, two 60 kV switching stations, nine distribution substations, approximately 12 miles of 60 kV sub
transmission lines, and approximately 469 miles of 12 kV and 4kV distribution lines – including 223
miles of overhead lines and 245 miles of underground lines.
In 2018 CPAU staff completed a distribution system assessment report to begin the process of
understanding the distribution system upgrades that will be required to integrate increasing
penetration levels of distributed energy resources, particularly electric vehicles. Staff’s conclusion from
this assessment was that at the system level, there is sufficient capacity to accommodate DER growth
for the next five years. However, there are some subcomponents of the system that require further
assessment and monitoring (e.g. residential distribution transformers). The Citywide implementation
of Advanced Metering Infrastructure (AMI), which is planned to occur by 2022, will greatly enhance the
visibility into distribution system operational characteristics and further enable the integration of DERs
by offering new customer programs (such as, time varying rates).
Palo Alto’s current fiveyear capital plan for electric distribution facilities contemplates spending
approximately $16.5 million per year over this fiveyear period, primarily to fund infrastructure
replacement and new customer connections.
28 Although three lines would normally provide redundancy and backup power delivery to the City, all three lines run in a
common corridor on the bay side of the City, a corridor that is in close proximity to the Palo Alto Airport. The common
corridor and proximity to an airport means that the City’s power supply is susceptible to single events that can affect all
three lines, as happened in February of 2010 when a small aircraft hit the power lines resulting in a citywide power outage
for over 10 hours.
29 See this January 2016 staff report for additional background on the efforts to secure an additional transmission
interconnection point: https://www.cityofpaloalto.org/civicax/filebank/documents/50608.
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Section VIII: Lowincome Assistance Programs
38
Lowincome Assistance Programs VIII.
CPAU has three programs to provide financial assistance to lowincome customers:
Residential Energy Assistance Program (REAP): This program provides qualifying lowincome
residents with free energy efficiency measures and access to the Rate Assistance Program (RAP)
rate discount. For qualifying customers, a Home Assessment, an application to the RAP, and an
onsite customer evaluation for weatherization and energy efficiency measure installation,
including insulation and lighting, is provided. Customers may have refrigerators and/or furnaces
replaced if the need is found.
Rate Assistance Program (RAP): This program provides a 25% discount for electric and gas
charges for qualified customers. Applicants can qualify based on medical or financial need.
ProjectPLEDGE: This program provides a onetime contribution of up to $750 applied to the
utilities bill of qualifying residential customers. Eligibility criteria include experiencing recent
employment and/or health emergency events. Administered by CPAU, this program is funded
by voluntary customer contributions.
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Section IX: Localized Air Pollutants
39
Localized Air Pollutants IX.
Electric Vehicle Programs A.
Given that Palo Alto’s electricity supply is derived entirely from clean, carbon neutral generation
resources, the most important thing that the City can do at this point to improve local air quality is to
reduce the combustion of fossil fuels in the transportation sector – primarily through electrification of
vehicles. The City of Palo Alto Utilities has a number of programs to promote the adoption of electric
vehicles, a summary of which can be found in the 2017 Demand Side Management Annual Report. Two
of the current programs are listed below.
EV Charger Rebate Program In early 2017 CPAU launched an EV Charger Rebate program using funds
from monetizing Low Carbon Fuel Standard (LCFS) credits. Rebates are targeted towards multifamily
and mixeduse properties, schools and nonprofits. Along with the launch, new online resources were
created, including the EV calculator tool.
Online EV/PV Calculator CPAU launched an online calculator tool for residents to evaluate the costs
and benefits of installing rooftop solar. In addition, residents can now evaluate different electric
vehicles and see the financial impacts and environmental benefits of charging vehicles using Palo Alto’s
carbon neutral electricity. The online calculator uses satellite imagery of Palo Alto homes as well as
current CPAU electricity rates to produce rooftop solar system designs and cost estimates tailored to
Palo Alto.
Local Renewable Energy Programs B.
In addition to the local renewable electricity generation programs previously mentioned, Palo Alto also
has a Solar Hot Water Program which can replace natural gas combustion and thereby improve local
air quality.
Solar Hot Water Program Palo Alto launched the solar water heating (SWH) program in May 2008, in
advance of a State law requiring natural gas utilities to offer incentives. This program offers rebates of
up to $2,719 for residential systems and up to $100,000 for commercial and industrial systems. A
sample of these installations is inspected for quality and program compliance by an independent
contractor. The program was recently extended through 2020. A total of 60 systems have been
installed as of June 30, 2017; 54 of these are residential. From 2008 to 2017 $337,911.37 in rebates
were disbursed. In the fiscal year 2017 this program resulted in annual energy savings of 19,826 therms
and 13,387 kWh.
Electrification of Space and Water Heating Programs C.
The Electrification Work Plan highlighted the potential of lowering carbon emissions and improving
local air quality by electrification of building water and space heating loads thereby removing local
combustion of natural gas. A description of more programs to promote electrification of space and
water heating can be found in the 2017 Demand Side Management Report.Two of the current
electrification programs are listed below.
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Section IX: Localized Air Pollutants
40
Heat Pump Water Heater Pilot Program The goal of this program is reduction of greenhouse gas
(GHG) emissions through switching from natural gas appliances to highefficiency electric appliances.
Installation of heat pump water heaters (HPWHs) has been identified as a good starting candidate for a
pilot program. The pilot program—launched in the spring of 2016—was designed to facilitate the
installation of HPWHs in singlefamily homes. In April 2017, the City hosted its first HPWH workshop to
educate the community, including contractors, on the technology and installation of HPWHs.
Multifamily Gas Furnace Retrofit Pilot Program CPAU has been awarded a 2018 Climate Protection
Grant Program from the Bay Area Air Quality Management District (BAAQMD) for a Multifamily Gas
Furnace Pilot Program. The grant period is two years from 20192020.
The Multifamily Gas Furnace Retrofit Pilot targets apartment buildings to replace existing inunit gas
wall furnaces with high efficiency air source heat pumps. Heat pump systems are far more energy
efficient than gas furnaces, eliminate GHG emissions associated with gasfired space heaters, while
improving air quality within the dwelling units. However, many questions still exist regarding cost
effectiveness, building electrical capacity and other technological and logistical hurdles for replacing
gas furnace to heat pump systems in multifamily buildings. This pilot will identify the technical and
logistical hurdles as well as potential solutions, and will document the retrofit cost, energy savings,
avoided GHG emissions as well as other indoor air pollutants from the gas furnace.
Refrigerant Recycling Program D.
Ensuring that refrigerants are properly disposed of also improves local air quality. CPAU has also been
awarded a 2018 Climate Protection Grant Program from the BAAQMD for a Refrigerator Recycling
Program. The grant period is two years from 20192020.
Although the City’s GreenWaste contractor can pick up and remove old refrigerators from customer
houses, they are not certified to recycle the foams and refrigerant chemicals to the level that the US
EPA Responsible Appliance Disposal (RAD) program requires. RAD requirements go above and beyond
the State of California minimum recycling requirements.
This BAAQMD grant will to cover a portion of the cost of recycling in order to enable us to both claim
EE savings as well as meet the RAD standards in a costeffective manner.
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Section X: Path Forward & Next Steps
41
Path Forward & Next Steps X.
Recommended Portfolio A.
Because almost six years remain before Palo Alto must make its major planning decision of the EIRP
planning period (the Western contract renewal decision), it is difficult to definitively identify a single
recommended portfolio at this time. The base case in this IRP assumes that Palo Alto will renew the
Western contract at the maximum allocation level. However, given the substantial amount of
uncertainty related to the cost and output levels of this resource (as described in the Future
Procurement Needs and Portfolio Rebalancing section of this report), staff is actively reviewing
attractive alternatives which could replace the entire Western contract when it expires in 2024.
If, in fact, Palo Alto determines that the costs associated with a renewed Western contract are too
high, or too uncertain, CPAU staff would immediately begin working to replace this resource (which
currently supplies nearly 40% of the City’s electric load) with a different carbon neutral supply
resource. As such, the City would continue on its path to meeting or exceeding both the state’s RPS
procurement requirements and GHG emission reduction targets. Figure 9 below depicts Palo Alto’s
projected electric resource supply mix in 2030 where a large portion of this mix currently consists of
undetermined carbonneutral resources. Given the City’s current policies and the state’s RPS and GHG
emissions mandates, staff can confidently say that these resources will either be hydroelectric or
renewable.
Figure 9: Palo Alto’s Projected Resource Supply Mix in 2030
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Section X: Path Forward & Next Steps
42
GHG Emissions B.
CARB’s 2017 Scoping Plan identified GHG emissions targets for the entire state, as well as individual
economic sectors, including the electricity industry. The Scoping Plan established an overall electric
sector GHG target for 2030 of 30 to 53 million metric tonnes (MMT) of CO2e, of which Palo Alto’s pro
rata share (based on load) is 0.174%, or 52,049 to 92,103 MT CO2e. As Figure 10 indicates, given its
electric supply portfolio consisting entirely of carbonfree resources (hydroelectric, wind, solar, and
biogas), Palo Alto is on track to emit far less than even the most aggressive end of the target range
identified in the CARB Scoping Plan.
Scenario AnalysisC.
As described in Section II.D of this report, an important element of integrated resource planning is to
put the recommended portfolio through scenario and risk analysis, to assess its performance under a
range of potential conditions. Staff has performed such a scenario analysis around the recommended
portfolio presented in this report, evaluating its performance while varying the following factors:
market prices, hydrological conditions, environmental regulations affecting hydro resource operations,
DER adoption rates, and natural customer load growth rates. Under all cases examined, however, the
City’s supply portfolio remained in compliance with the RPS and GHG emissions targets set forth in SB
350, all while keeping Palo Alto customers’ retail rates lower than the statewide average retail rates.
Figure 10: CPAU Electric Supply GHG Emissions (20052030)
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Section X: Path Forward & Next Steps
43
Next StepsD.
As there is so much uncertainty regarding the Western resource, and because the decision is such a
consequential one, it merits a followup analysis closer to the contract renewal date, which is currently
scheduled for mid2020. Even after that, WAPA’s 2025 Power Marketing Plan indicates that the City
will have until July 2024 to make a decision to reduce or reject its allocated share of the future
Western contract, which is expected to be approximately as large as its current share. The additional
analysis regarding this decision should include:
1. An examination of the City’s net load forecast and associated uncertainties, in line with the
Draft DER Plan discussed with the UAC in November 2017, with particular emphasis on how it
may be affected by customer adoption of DERs (EVs, Demand Response, Energy Efficiency, Solar
PV, storage, and building electrification) in order to avoid stranding assets.
2. An update and extension of CPAU’s supply portfolio analysis, including updates to the hourly
LMP forecasts and the costs, assumptions, and uncertainties associated with all resource
options.
3. Analysis of the projected costs, output, and flexibility of the renewed Western contract, to
reduce the amount of outstanding uncertainty around this resource.
4. Advocating for flexible contractual provisions in the new Western contract, and examining the
legal and economic merits and risks associated with committing to the Western resource for 30
more years.
Aside from the Western contract decision, staff will be actively following state regulators’ activities
related to electric supply portfolio GHG emissions accounting and allocation of statewide GHG
emissions reduction targets. While the City’s current GHG emissions accounting methodology (adopted
by the City Council in 2013 with the Carbon Neutral Plan) for electric supplies is based on a net annual
accounting of the City’s market power purchases (which are assumed to have the statewide average
GHG emissions intensity), staff is aware that state regulators are evaluating alternative GHG emissions
accounting methodologies, including various types of hourly accounting approaches.
And of course, staff will continue its activities in pursuit of lowering the overall cost to serve customer
loads. These include continuing to optimize the use of the City’s Calaveras resource, evaluating the
benefits of the NCPA pool, and/or the procurement of alternative scheduling services for its renewable
resources.
Key Issues to Monitor & Attempt to Influence E.
In the course of developing this EIRP, CPAU staff has identified a number of important issues and
sources of uncertainty to closely monitor and attempt to positively influence over the course of the
planning period. Some of the primary issues and uncertainties that staff will be focused on include:
Cost and operations of Western hydroelectric resource: environmental restoration cost, water
delivery timing and priorities, Western transmission upgrade needs, environmental regulations
affecting water releases, and longterm climate change
Frequency and magnitude of economic curtailment of solar PV resources
Renewing the FERC license of the Calaveras hydroelectric project
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Section X: Path Forward & Next Steps
44
Seasonal variation in CAISO energy market prices, given the overall generation profile of CPAU’s
resource portfolio
Changes in overall energy market price and changes in carbon allowance prices associated with
State's capandtrade program
Increased market prices related to loadfollowing capacity and ancillary services
Customer load profiles change and loss of customer loads available for the City to serve
New legislative and regulatory mandates
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Section XI: Appendices
XI—1
Appendices XI.
Key Supplemental Reports and DocumentsA.
1.NCPACAISO Metered SubSystem Agreement
2.TenYear Electric Energy Efficiency Goals (2017)
3.Energy Storage Assessment Report (2017)
4.Proposed Distributed Energy Resources Plan (2017)
5.Distribution System Assessment Report (2018)
6.Demand Side Management Annual Report (2018)
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Section XI: Appendices
XI—2
RPS Procurement Plan B.
CITY OF PALO ALTO’S
RENEWABLE PORTFOLIO STANDARD
PROCUREMENT PLAN
Version 3
December 2018
REVISION HISTORY
Version Date Resolution Description
3 12/3/18 Updated to reflect Senate Bill 350 (2015) requirements
2 11/12/13 9381 Updated to reflect adoption of final CEC regulations, effective
10/1/13, permitting the City to adopt rules for Excess Procurement,
Compliance Delay, Cost Limitations, Portfolio Balancing Reductions,
and Historic Carryover. Other nonsubstantive clean up.
1 12/12/11 9215 Original version per Senate Bill X1 2 (2011) requirements
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Section XI: Appendices
XI—3
TABLE OF CONTENTS
INTRODUCTION ....................................................................................................................... XI—4
A. PURPOSE OF THE PLAN (PUC § 399.30(A))................................................................... XI—4
B. PLAN ELEMENTS ............................................................................................................... XI—5
1. Compliance Period Definitions ........................................................................................... XI—5
2. Procurement Requirements ................................................................................................ XI—5
3. Portfolio Content Categories (PCC)................................................................................... XI—6
4. Portfolio Balancing Requirements..................................................................................... XI—6
5. LongTerm Contract Requirement ..................................................................................... XI—7
6. Reasonable Progress ............................................................................................................. XI—7
C. OPTIONAL COMPLIANCE MEASURES ............................................................................. XI—7
1. Excess Procurement (PUC §399.13(a)(4)(B)) ................................................................... XI—7
2. Delay of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5)) .................................... XI—8
3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c)) .......................... XI—10
4. Portfolio Balance Requirement Reduction (PUC § 399.16(e)) .................................. XI—11
5. Historic Carryover ................................................................................................................ XI—11
6. Large Hydro Exemption (PUC § 399.30(l)) ..................................................................... XI—13
D. ADDITIONAL PLAN COMPONENTS ............................................................................... XI—14
1. Exclusive Control (PUC § 399.30(n))................................................................................ XI—14
2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f)) ........................................ XI—14
3. Annual Review ................................................................................................................. XI—15
4. Plan Modifications/Amendments..................................................................................... XI—15
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Section XI: Appendices
XI—4
INTRODUCTION
This document presents the City of Palo Alto Utilities’ (CPAU) Renewable Portfolio Standard
Procurement Plan (RPS Procurement Plan), as required for compliance with Senate Bill (SB) 350.30 This
legislation, which was signed into law in the 2015 Session of the Legislature, modified the state’s
renewable portfolio standard (RPS) program and set forth RPS requirements applicable to all load
serving entities in the state. Pursuant to Public Utility Code § 399.30(a) and Section 3205 of the
California Energy Commission’s (CEC) “Enforcement Procedures for the Renewables Portfolio Standard
for Local Publicly Owned Electric Utilities”31 (RPS Regulations), each POU must adopt and implement a
renewable energy resources procurement plan (RPS Procurement Plan). SB X1 2, signed into law in
2011, directed the CEC to adopt regulations specifying procedures for enforcement of the RPS for
Publicly Owned Utilities.
This RPS Procurement Plan replaces the RPS Procurement Plan approved by the Palo Alto City Council
(City Council) on November 12, 2013 (Resolution No. 9381, Staff Report No. 4168) and is consistent
with the provisions set forth in the CEC’s RPS Regulations, which have been adopted by the CEC and
approved by the Office of Administrative Law, with an effective date of April 12, 2016.32
CPAU’s RPS Procurement Plan consists of:
A. Purpose of the plan;
B. Plan Elements;
C. Measures that address each of the optional provisions set forth in §399.30(d) and RPS
Regulations Section 3206; and
D. Additional provisions.
Where appropriate, this RPS Procurement Plan includes section citations to the Public Utilities Code
(PUC) and the CEC’s RPS Regulations.
A. PURPOSE OF THE PLAN (PUC § 399.30(A))
In order to fulfill unmet longterm generation resource needs, the City Council adopts and implements
this RPS Procurement Plan. This Plan requires the utility to procure a minimum quantity of electricity
30 SB 350 (2015) was signed by California’s Governor on October 7, 2015, and made significant revisions to Public Utilities
Code sections 399.11399.32, the California Renewable Portfolio Standard Program.
31 California Code of Regulations, Title 20, Division 2, Chapter 13, Sections 3200 3208 and Title 20, Division 2, Chapter 2,
Section 1240.
32 At the time of writing for this edition of CPAU’s RPS Procurement Plan, the RPS Regulations had not been updated with
SB 350 and subsequent legislative requirements. Where both Public Utility Codes and RPS Regulations are cited but the RPS
Regulations are outdated, CPAU’s RPS Procurement Plan will reflect the more current Public Utility Codes.
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Section XI: Appendices
XI—5
products from eligible renewable energy resources, including renewable energy credits (RECs), as a
specified percentage of CPAU’s total kilowatthours of electrical energy sold to its retail enduse
customers, during each compliance period, to achieve the targets specified in SB 350 and the RPS
Regulations. This RPS Procurement Plan establishes the framework for achieving the minimum
requirements under SB 350 and the RPS Regulations, and does not include or preclude actions taken by
CPAU to achieve the City Council’s goals.
B. PLAN ELEMENTS
CPAU will comply with the requirements for renewables procurement targets set forth in SB 350 and
the applicable enforcement procedures codified in the CEC’s RPS Regulations, including
implementation of the following Plan Elements:
1. Compliance Period Definitions
CPAU has adopted the relevant compliance period definitions identified in PUC § 399.30(b).
2. Procurement Requirements
CPAU shall meet or exceed the following procurement targets of renewable energy resources
for each compliance period per PUC §§ 399.30(c)(1) and (2) and the CEC’s RPS Regulations:
Compliance Period 1 Target 20% × (CPAU Retail Sales2011_+ CPAU Retail Sales2012 + CPAU Retail
Sales2013).
Compliance Period 2 Target 20% × CPAU Retail Sales2014 + 20% × CPAU Retail Sales2015 + 25% ×
CPAU Retail Sales2016
Compliance Period 3 Target 27% × CPAU Retail Sales2017 + 29% × CPAU Retail Sales2018 + 31% ×
CPAU Retail Sales2019 + 33% × CPAU Retail Sales2020
Compliance Period 4 Target 34.75% × CPAU Retail Sales2021 + 36.5% × CPAU Retail Sales2022 +
38.25% × CPAU Retail Sales2023 + 40% × CPAU Retail Sales2024
Compliance Period 5 Target 41.67% × CPAU Retail Sales2025 + 43.33% × CPAU Retail Sales2026 +
45% × CPAU Retail Sales2027
Compliance Period 6 Target 46.67% × CPAU Retail Sales2028 + 48.33% × CPAU Retail Sales2029 +
50% × CPAU Retail Sales2030
Annually thereafter, CPAU shall procure renewable energy resources equivalent to at least fifty
percent (50%) of retail kilowatthour sales.
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Section XI: Appendices
XI—6
The procurement targets listed for each individual year above are soft targets. That is, by the end
of each Compliance Period, CPAU’s RPS total for the period has to equal the sum of the annual
targets, but the targets do not have to be achieved in any one year.
3. Portfolio Content Categories (PCC)
CPAU adopts the definitions for qualifying electric products and Portfolio Content Categories
(PCC) per Sections 3202 and 3203 of the CEC’s RPS Regulations.
a.How CPAU Plans to Achieve its RPS Requirements per Section 3205(a)(1) of the CEC’s RPS
Regulations
CPAU’s RPS portfolio will include grandfathered contracts (commonly referred to as
“PCC 0”), which are executed prior to June 1, 2010, and PCC 1 eligible resources, which
are typically directly or dynamically connected to a California balancing authority.
CPAU’s RPS portfolio may also include PCC 2 eligible resources that are scheduled into a
California balancing authority, and PCC 3 eligible resources, which are typically
unbundled renewable energy credits (RECs). PCC 0 resources are defined in Section
3202(a)(2) of the CEC’s RPS Regulations, while PCC 1, 2, and 3 resources are defined in
Section 3203 of the CEC’s RPS Regulations. CPAU shall determine the category to which
each procured resource belongs.
In its 2011 through 2017 RPS Compliance Reports, CPAU listed a total of five PCC 0
contracts. All five of these contracts extend through the end of Compliance Period 3,
and all have achieved commercial operation. On their own, these PCC 0 contracts were
sufficient to enable CPAU to meet its Compliance Period 1 and 2 RPS targets.
CPAU has currently executed six contracts for PCC 1 resources. The first five of these,
executed between 2012 and 2014, have all commenced operation, between 2014 and
2016. The sixth PCC 1 contract, executed in 2016, is contracted to commence operation
in 2021. With these six PCC 1 resources, along with its five PCC 0 contracts, CPAU
forecasts that its renewable energy supplies will be well in excess of its procurement
requirements through at least Compliance Period 6.
4. Portfolio Balancing Requirements
In satisfying the procurement requirements listed in section B.3 of this RPS Procurement Plan,
CPAU shall also satisfy the legallyrequired portfolio balancing requirements specifying the
limits on quantities for PCC 1 and PCC 3 per PUC § 399.30(c)(3), §§ 399.16(c)(1) and (2). CPAU
shall apply the formulae specified in Section 3204(c) of the CEC’s RPS Regulations to determine
these portfolio balance requirements. Renewable energy procured from PCC 0 contracts shall
be excluded from these portfolio balancing requirement formulae.
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Section XI: Appendices
XI—7
5. LongTerm Contract Requirement
In meeting the RPS procurement requirements identified in section B.3 of this RPS Procurement
Plan, CPAU is subject to longterm contract requirements. Consistent with Public Resources
Code § 399.13(b), CPAU may enter into a combination of longand shortterm contracts for
electricity and associated renewable energy credits. Beginning January 1, 2021, at least 65
percent of CPAU’s procurement that counts toward the RPS requirement of each compliance
period shall be from its contracts of 10 years or longer or in its ownership or ownership
agreements for eligible renewable energy resources.
6. Reasonable Progress
CPAU shall demonstrate that it is making reasonable progress towards ensuring that it shall
meet its compliance period targets during intervening years per PUC §§ 399.30(c)(2).
C. OPTIONAL COMPLIANCE MEASURES
As permitted by Section 3206(a) of the CEC’s RPS Regulations, the City Council hereby adopts rules
permitting the use of each of the following five optional compliance measures included in the CEC’s
RPS Regulations: Excess Procurement, Delay of Timely Compliance, Cost Limitations, Portfolio Balance
Requirement Reduction, and Historic Carryover. The City Council also hereby adopts rules permitting
the use of the Large Hydro Exemption as described in PUC § 399.30(l).
1. Excess Procurement (PUC §399.13(a)(4)(B))
a.Adoption of Excess Procurement Rules
The City Council has elected to adopt rules permitting CPAU to apply excess
procurement in one compliance period to a subsequent compliance period, as described
in Section 3206(a)(1) of the CEC’s RPS Regulations.
b.Limitations on CPAU’s Use of Excess Procurement
CPAU shall be allowed to apply Excess Procurement from one compliance period to
subsequent compliance periods as long as the following conditions are met:
1. Excess Procurement shall only include generation from January 1, 2011 or later.
2. In calculating the quantity of Excess Procurement, CPAU shall deduct from actual
procurement quantities, the total amount of procurement associated with contracts
of less than ten (10) years in duration.
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Section XI: Appendices
XI—8
3. Eligible resources must be from Content Category 1 or Content Category 2 or
Grandfathered Resources to be Excess Procurement. Resources from Content
Category 3 will not count towards Excess Procurement.
c.Excess Procurement Calculation
CPAU shall calculate its Excess Procurement according to formulae in section 3206
(a)(1)(D) of the CEC’s RPS Regulations.
d. City Council Review
CPAU’s use of the Excess Procurement to apply towards CPAU’s RPS procurement target
in any compliance period will be reviewed by the City Council during its annual review as
per section D.3 of this RPS Procurement Plan.
2. Delay of Timely Compliance (§ 399.30(d)(2), § 399.15(b)(5))
a.Adoption of Delay of Timely Compliance Rules
The City Council has elected to adopt rules permitting it to make a finding that
conditions beyond CPAU’s control exist to delay timely compliance with RPS
procurement requirements, as described in Section 3206(a)(2) of the CEC’s RPS
Regulations.
b.Delay of Timely Compliance Findings
The City Council may make a finding, based on sufficient evidence presented by CPAU
staff, and as described in this Section C.2, that is limited to one or more of the following
causes of delay, and shall demonstrate that CPAU would have met its RPS procurement
requirements but for the cause of the delay:
(1) Inadequate Transmission
i. There is inadequate transmission capacity to allow for sufficient
electricity to be delivered from CPAU’s proposed eligible renewable energy
resource projects using the current operational protocols of the California
Independent System Operator’s Balancing Authority Area.
ii. If the City Council’s delay finding rests on circumstances related to
CPAU’s transmission resources or transmission rights, the City Council may find
that:
a.) CPAU has undertaken, in a timely fashion, reasonable
measures under its control and consistent with its obligations under local,
state, and federal laws and regulations, to develop and construct new
transmission lines or upgrades to existing lines intended to transmit
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Section XI: Appendices
XI—9
electricity generated by eligible renewable energy resources, in light of its
expectation for cost recovery.
b.) CPAU has taken all reasonable operational measures to
maximize costeffective purchases of electricity from eligible renewable
energy resources in advance of transmission availability.
(2) Permitting, interconnection, or other factors that delayed procurement or
insufficient supply.
i. Permitting, interconnection, or other circumstances have delayed
procured eligible renewable energy resource projects, or there is an insufficient
supply of eligible renewable energy resources available to CPAU.
ii. In making its findings relative to the existence of this condition,
the City Council’s deliberations shall include, but not be limited to the following:
a) Whether CPAU prudently managed portfolio risks, including,
but not limited to, holding solicitations for RPSeligible resources with
outreach to market participants and relying on a sufficient number of
viable projects;
b) Whether CPAU sought to develop its own eligible renewable
energy resources, transmission to interconnect to eligible renewable
energy resources, or energy storage used to integrate eligible renewable
energy resources.
c) Whether CPAU procured an appropriate minimum margin of
procurement above the minimum procurement level necessary to comply
with the renewables portfolio standard to compensate for foreseeable
delays or insufficient supply;
d) Whether CPAU has taken reasonable measures, under its
control to procure costeffective distributed generation and allowable
unbundled renewable energy credits;
(3) Unanticipated curtailment to address needs of the balancing authority.
c.Procedures upon Approving Waiver:
In the event of a Waiver of Timely Compliance due to any of the factors set forth above,
CPAU shall implement the following procedures:
(1) Establish additional reporting for intervening years to demonstrate that
reasonable actions under the CPAU’s control are being taken (§399.15(b)(6)).
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Section XI: Appendices
XI—10
(2) Require a demonstration that all reasonable actions within the CPAU’s control
have been taken to ensure compliance in order to grant the waiver (§
399.15(b)(7)).
3. Cost Limitations for Expenditures (PUC § 399.30(d), § 399.15(c))
a.Cost Limitations for Expenditures
The City Council has elected to adopt rules for cost limitations on the procurement
expenditures used to comply with CPAU’s procurement requirements, as described in
Section 3206(a)(3) of the CEC’s RPS Regulations. These cost limitation rules are
intended to be consistent with PUC §399.15(c).
b. Considerations in Development of Cost Limitation Rules
In adopting cost limitation rules, the City Council has relied on the following:
1) This Procurement Plan;
2) Procurement expenditures that approximate the expected cost of building,
owning, and operating eligible renewable energy resources;
3) The potential that some planned resource additions may be delayed or canceled;
and
4) Local and regional economic conditions and the ability of CPAU’s customers to
afford produced or procured energy products. These economic conditions may
include but are not limited to unemployment, wages, cost of living expenses, the
housing market, and cost burden of other utility rates on the same customers.
The City Council may also consider cost disparities between customer classes
within Palo Alto, and between Palo Alto customers and other Publicly Owned
Utility and Investor Owned Utility customers in the region.
c. Cost Limitations
The City of Palo Alto’s current RPS policy requires that CPAU pursue a target level of
renewable purchases of 33% while “[e]nsuring that the retail rate impact for renewable
purchases does not exceed 0.5 ¢/kWh on average,” i.e., the cumulative incremental cost
of all renewable resources over and above the estimated cost of an equivalent volume
and shape of alternative nonRPS resources shall not cause a retail rate impact in excess
of 0.5 ¢/kWh on average. This limit was first established by the City Council in October
2002 based on public input, and the goal of balancing resource reliability and cost
considerations in the consideration of investment in renewable and energy efficiency
resources.
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Section XI: Appendices
XI—11
d. Actions to be Taken if Costs Exceed Adopted Cost Limitation
If costs are anticipated to exceed the cost limitations set by the City Council, staff will
present proposals to the City of Palo Alto’s Utilities Advisory Commission to either
reduce the RPS requirements or increase the cost limitation. Staff and the Commission’s
recommendations will then be taken to the City Council for action.
4. Portfolio Balance Requirement Reduction (PUC § 399.16(e))
a.Adoption of Portfolio Balance Requirement Reduction Rules
The City Council has elected to adopt rules that allow for the reduction of the portfolio
balance requirement for PCC 1 for a specific compliance period, consistent with PUC
§399.16(e), as described in Section 3206(a)(4) of the CEC’s RPS Regulations.
b.Portfolio Balance Requirement Reduction Rules
CPAU may reduce the portfolio balance requirement for PCC1 for a specific compliance
period, consistent with PUC §399.16 (e) and the following:
1. The need to reduce the portfolio balance requirements for PCC 1 must have
resulted because of conditions beyond CPAU’s control, as provided in Section
3206(a)(2) of the CEC’s RPS Regulations.
2. CPAU may not reduce its portfolio balance requirement for PCC 1 below 65
percent for any compliance period after December 31, 2016.
3. Any reduction in portfolio balance requirements for PCC 1 must be adopted at a
publicly noticed meeting, providing at least 10 calendar days’ notice to the CEC,
and include an updated renewable energy resources procurement plan detailing
the portfolio balance requirement changes.
5. Historic Carryover
a.Adoption of Historic Carryover Rules
The City Council has elected to adopt rules to permit its use of Historic Carryover, as
defined in Section 3206(a)(5) of the RPS Regulations, to meet its RPS procurement
targets. Current calculations indicate that CPAU has Historic Carryover due to CPAU’s
early investment in renewable energy resources.
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Section XI: Appendices
XI—12
b. Historic Carryover Procurement Criteria
CPAU’s use of Historic Carryover is subject to section 3206 (a)(5) of the CEC’s RPS
Regulations, including the following:
1) Procurement generated before January 1, 2011 may be applied to CPAU’s RPS
procurement target for the compliance period ending December 31, 2013, or
for any subsequent compliance period; and
2) The procurement must also meet the criteria of Section 3202 (a)(2) of the
CEC’s RPS Regulations; and
3) The procurement must be in excess of the sum of the 20042010 annual
procurement targets defined in Section 3206(a)(5)(D) of the CEC’s RPS
Regulations; and
4) The procurement cannot have been applied to the RPS of another state or to a
voluntary claim.
5) The Historic Carryover must be procured pursuant to a contract or ownership
agreement executed before June 1, 2010.
6) Both the Historic Carryover and the procurement applied to CPAU’s annual
procurement targets must be from eligible renewable energy resources that
were RPSeligible under the rules in place for retail sellers at the time of
execution of the contract or ownership agreement, except that the
generation from such resources need not be tracked in the Western
Renewable Energy Generation Information System.
c. Historic Carryover Formula
CPAU will calculate its Historic Carryover according to formulae in section 3206 (a)(5)C)
and (D) of the CEC’s RPS Regulations.
d. Historic Carryover Claims
The number of RECs qualifying for Historic Carryover is dependent upon the acceptance
by the CEC of CPAU’s applicable procurement claims for January 1, 2004 – December 31,
2010, which are due to the CEC within 90 calendar days after the effective date of the
CEC’s RPS Regulations (October 30, 2013). The Historic Carryover submittal shall also
include baseline calculations, annual procurement target calculations, and any other
pertinent data.
e. Council Review
CPAU’s use of the Historic Carryover to apply towards CPAU’s RPS procurement target in
any compliance period will be reviewed by the City Council during its annual review as
per section D.3 of this RPS Procurement Plan.
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Section XI: Appendices
XI—13
6. Large Hydro Exemption (PUC § 399.30(l))
a.Adoption of Large Hydro Exemption Rules
The City Council has elected to adopt rules permitting CPAU to reduce its annual RPS
procurement requirements, as described in PUC §399.30(l).
b.Limitations on CPAU’s Use of the Large Hydro Exemption
CPAU shall be allowed to invoke the Large Hydro Exemption as long as the following
conditions are met:
1. During a year with in a compliance period, CPAU shall have received greater than
50% of its retail sales from large hydroelectric generation, which is defined as
electricity generated from a hydroelectric facility that is not an eligible renewable
energy resource.
2. The large hydroelectric generation is produced at a facility owned by the federal
government as a part of the federal Central Valley Project or a joint powers agency.
3. Only large hydroelectric generation that is procured under an existing agreement
effective as of January 1, 2015, or an extension or renewal of that agreement, shall
counted in the determination that CPAU has received more than 50 percent of its
retail sales from large hydroelectric generation in any year.
c.Large Hydro Exemption Calculation
CPAU’s annual RPS procurement target for a year in which the Large Hydro Exemption is
invoked shall equal the lesser of (a) the portion of CPAU’s retail sales unsatisfied by its
large hydroelectric generation or (b) the annual RPS procurement soft target for that
year, as listed in section B.2 of this RPS Procurement Plan. CPAU’s RPS procurement
requirement for the compliance period that includes said year shall be adjusted to
reflect any reduction in CPAU’s annual RPS procurement target pursuant to this section.
d. City Council Review
CPAU’s use of the Large Hydro Exemption to reduce its annual RPS procurement target
in any compliance period will be reviewed by the City Council during its annual review as
per section D.3 of this RPS Procurement Plan.
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Section XI: Appendices
XI—14
D. ADDITIONAL PLAN COMPONENTS
1. Exclusive Control (PUC § 399.30(n))
In all matters regarding compliance with the RPS Procurement Plan, CPAU shall retain exclusive control
and discretion over the following:
a. The mix of eligible renewable energy resources procured by CPAU and those additional
generation resources procured by CPAU for purposes of ensuring resource adequacy
and reliability.
b. The reasonable costs incurred by CPAU for eligible renewable energy resources owned
by it.
2. Deliberations & Reporting (PUC § 399.30(e), § 399.30(f))
a.Deliberations on Procurement Plan (§399.30(f)):
(1) Public Notice: Annually, CPAU shall post notice of meetings if the CPA Council
will deliberate in public regarding this RPS Procurement Plan.
(2)Notice to the California Energy Commission (CEC): Contemporaneous with the
posting of a notice for such a meeting, CPAU shall notify the CEC of the date,
time and location of the meeting in order to enable the CEC to post the
information on its Internet website.
(3) Documents and Materials Related to Procurement Status and Plans: When CPAU
provides information to the CPA Council related to its renewable energy
resources procurement status and future plans, for the City Council’s
consideration at a noticed public meeting, CPAU shall make that information
available to the public and shall provide the CEC with an electronic copy of the
documents for posting on the CEC’s website.
b. Compliance Reporting (Section 3207 of the CEC RPS Regulations)
(1) CPAU shall submit an annual report to the CEC by July 1. The annual reports shall
include the information specified in Section 3207(c) of the CEC RPS Regulations.
(2) By July 1, 2021; July 1, 2025; July 1, 2028; July 1, 2031; and by July 1 of each year
thereafter, CPAU shall submit to the CEC a compliance report that addresses the
annual reporting requirements of the previous section, and information for the
preceding compliance period as specified in Section 3207(d) of the CEC RPS
Regulations.
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Section XI: Appendices
XI—15
3. Annual Review
CPAU’s RPS Procurement Plan shall be reviewed annually by the City Council in accordance with
CPAU’s RPS Enforcement Program.
4. Plan Modifications/Amendments
This RPS Procurement Plan may be modified or amended by an affirmative vote of the City Council
during a public meeting. Any City Council action to modify or amend the plan must be publicly noticed
in accordance with Section D.2.a.
Effective Date: This plan shall be effective on _______________, 2018.
APPROVED AND ADOPTED this _________ day of __________________, 2018.
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Section XI: Appendices
XI—16
RPS Enforcement Program C.
CITY OF PALO ALTO’s
RENEWABLE PORTFOLIO STANDARD ENFORCEMENT
PROGRAM
Version 2
December 2018
REVISION HISTORY
Version Date Resolution Description
2 12/3/18 Updated to reflect Senate Bill 350 (2015) requirements
1 12/12/11 9215 Original version per Senate Bill X1 2 (2011) requirements
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Section XI: Appendices
XI—17
1. The City shall have a program for the enforcement of a Renewable Portfolio Standard (RPS)
program, which shall include all of the provisions set forth herein and shall be known as the
City’s RPS Enforcement Program;
2. The RPS Enforcement Program shall be effective on January 1, 2012;
3. Not less than ten (10) days advance notice shall be given to the public before any meeting is
held to make a substantive change to the RPS Enforcement Program;
4. Annually, the City Manager or his designee, the Utilities General Manager, shall cause to be
reviewed the City’s RPS Procurement Plan to determine compliance with the RPS Enforcement
Program;
5. Annual review of the RPS Procurement Plan shall include consideration of each of the following
elements:
A. By December 31, 2017, December 31, 2018, and December 31, 2019:
1. Ensure that the City is making reasonable progress toward meeting the
December 31, 2020 compliance obligation of 33% renewable resources
electricity, consistent with the RPS Procurement Plan.
B. December 31, 2020 (end of Compliance Period 3),
1. Verify that that the City procured sufficient electricity products to meet the
sum of 27% of its 2017, 29% of its 2018, 31% of its 2019, and 33% of its 2020
retail sales with eligible renewable resources from the specified Content
Categories, consistent with the RPS Procurement Plan;
C. By December 31, 2021, December 31, 2022, and December 31, 2023:
1. Ensure that the City is making reasonable progress toward meeting the
December 31, 2024 compliance obligation of 40% renewable resources
electricity, consistent with the RPS Procurement Plan.
D. December 31, 2024 (end of Compliance Period 4),
1. Verify that that the City procured sufficient electricity products to meet the
sum of 34.75% of its 2021, 36.5% of its 2022, 38.25% of its 2023, and 40% of its
2024 retail sales with eligible renewable resources from the specified Content
Categories, consistent with the RPS Procurement Plan;
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Section XI: Appendices
XI—18
E. By December 31, 2025 and December 31, 2026:
1. Ensure that the City is making reasonable progress toward meeting the
December 31, 2027 compliance obligation of 45% renewable resources
electricity, consistent with the RPS Procurement Plan.
F. December 31, 2027 (end of Compliance Period 5),
1. Verify that that the City procured sufficient electricity products to meet the
sum of 41.67% of its 2025, 43.33% of its 2026, and 45% of its 2027 retail sales
with eligible renewable resources from the specified Content Categories,
consistent with the RPS Procurement Plan;
G. By December 31, 2028 and December 31, 2029:
1. Ensure that the City is making reasonable progress toward meeting the
December 31, 2030 compliance obligation of 50% renewable resources
electricity, consistent with the RPS Procurement Plan.
H. December 31, 2030 (end of Compliance Period 6),
1. Verify that that the City procured sufficient electricity products to meet the
sum of 46.67% of its 2028, 48.33% of its 2029, and 50% of its 2030 retail sales
with eligible renewable resources from the specified Content Categories,
consistent with the RPS Procurement Plan;
I. December 31, 2031 and annually thereafter,
1. Verify that that the City procured sufficient electricity products to meet 50% of
its retail sales with eligible renewable resources from the specified Content
Categories, consistent with the RPS Procurement Plan;
J. If targets in any compliance period are not met, the City must:
1. Review the applicability of applying Excess Procurement from a previous
Compliance Period or Historic Carryover consistent with the provisions of the
RPS Procurement Plan;
2. Ensure that any Waiver of Timely Compliance was compliant with the
provisions in the RPS Procurement Plan;
3. Ensure that any Portfolio Balance Requirement Reduction was compliant with
the provisions in the RPS Procurement Plan; and
4. Review applicability and appropriateness of excusing performance based on
the Cost Limitations on Expenditures or the Large Hydro Exemption provisions
of the RPS Procurement Plan.
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Section XI: Appendices
XI—19
6. If it is determined that the City has failed to comply with the provisions of its RPS Procurement
Plan, the City Council shall take steps to correct any untimely compliance, including requiring
the City Manager or his designee, the Utilities General Manager to:
A. review the City’s RPS Procurement Plan to determine what changes, if any, are
necessary to ensure compliance in the next Compliance Period;
B. report quarterly to the City Council regarding the progress being made toward
meeting the compliance obligation for the next Compliance Period; and
C. report to the City Council regarding the status of meeting subsequent compliance
targets, and all steps being taken to ensure that the obligation is timely met.
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Section XI: Appendices
XI—21
Energy Balance Table (EBT) ii.
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
Energy Balance Table
Form CEC 110 (May 2017)
Scenario Name: Expected Units = MWh
Yellow fill relates to an application for confidentiality.
NET ENERGY FOR LOAD CALCULATIONS 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
1 Retail sales to enduse customers 3%913,986 911,077 907,555 904,572 903,149 902,329 902,293 902,447 902,638 903,238 903,835 905,452
2Other loads 600 27,438 27,332 27,227 27,960 27,914 27,887 27,908 27,911 27,916 27,934 27,952 28,001
3 Unmanaged net energy for load 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453
4Managed retail sales to enduse customers No AAEE 0%913,986 913,986 913,986 911,077 907,555 904,572 903,149 902,329 902,293 902,447 902,638 903,238 903,835 905,452
5 Managed net energy for load 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453
6 Firm Sales Obligations 0 000000000000
7 Total net energy for load (5+6)941,423 941,423 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453
8 [Customerside solar generation]18,005 20,277 22,674 24,065 25,620 27,360 29,304 31,474 33,897 36,599 39,614 42,975 46,719 50,890
9 [Light Duty PEV electricity procurement requirement]7,316 9,510 11,967 14,704 17,685 20,933 24,444 28,246 32,275 36,579 41,144 46,008 51,073 56,406
10 [Other transportation electricity consumption/procurement requirement]000000000000
11 [Other electrification/fuel substitution; consumption/procurement requirement]HPWH& HPSH 146 288 476 730 1,049 1,423 1,876 2,431 3,083 3,831 4,639 5,507
EXISTING AND PLANNED GENERATION RESOURCES
UtilityOwned Generation Resources (not RPSeligible):
[list resource by name]2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
12a Collierville Hydroelectric 241,017 92,779 115,701 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668 131,668
LongTerm Contracts (not RPSeligible):
[list contracts by name]
12h Western Base Resource Generation Is auto-updating 541,539 411,405 409,511 385,814 364,289 364,289 364,289 364,289 364,289 364,289 364,289 364,289 364,289 364,289
12 Total energy from existing and planned supply resources (not RPSeligible) (sum of 12a…12n)782,556 504,184 525,212 517,482 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957 495,957
UtilityOwned RPSeligible Generation Resources:
[list resource by plant or unit]
13a New Spicer Hydroelectric Hydroelectric 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
LongTerm Contracts (RPSeligible):
[list contracts by name]
13i PROJECT #1 - HIGHWINDS Wind 48,207 42,664 42,668 42,754 42,721 42,708 42,672 42,711 42,671 42,709 42,722 12,615 0 0
13j PROJECT #2 - SHILOH #1 Wind 64,513 57,281 57,290 57,425 57,366 0 0 0 0 0 0 0 0 0
13k Santa Cruz (Buena Vist Landfill) Landfill Gas 9,853 8,961 8,961 8,986 8,961 8,961 8,961 8,985 8,961 1,449 0 0 0 0
13l Ox Mountain (Half Moon Bay) Landfill Gas 43,880 42,459 42,459 42,575 42,459 42,459 42,459 42,570 42,459 42,459 42,459 42,575 13,959 0
13m Keller Canyon Landfill Gas 14,894 13,827 13,827 13,865 13,827 13,827 13,827 13,863 13,827 13,827 13,827 13,865 9,205 0
13n Johnson Canyon (Ameresco) Landfill Gas 10,433 9,200 9,200 9,225 9,200 9,200 9,200 9,224 9,200 9,200 9,200 9,225 9,200 9,200
13…San Joaquin (Ameresco) Landfill Gas 30,283 27,468 27,468 27,544 27,468 27,468 27,468 27,540 27,468 27,468 27,468 27,544 27,468 27,468
13…EE Kettleman Land Solar 53,056 52,791 52,527 52,264 52,003 51,743 51,484 51,227 50,971 50,716 50,462 50,210 49,959 49,709
13…Elevation Solar C Solar 100,695 100,191 99,690 99,192 98,696 98,203 97,712 97,223 96,737 96,253 95,772 95,293 94,817 94,343
13…Western Antelope Blue Sky Ranch B Solar 50,367 50,115 49,864 49,615 49,367 49,120 48,874 48,630 48,387 48,145 47,904 47,665 47,426 47,189
13…Frontier Solar Solar 52,338 52,077 51,816 51,557 51,299 51,043 50,788 50,534 50,281 50,030 49,780 49,531 49,283 49,037
13…Hayworth Solar Solar 63,402 63,085 62,770 62,456 62,144 61,833 61,524 61,216 60,910 60,606 60,302 60,001 59,701 59,402
13…Wilsona Solar Solar 0 0 0 0 45,136 74,774 74,400 74,028 73,658 73,290 72,924 72,559 72,196 71,835
13…Palo Alto CLEAN Projects Solar 2,062 2,052 2,042 2,031 2,021 2,011 2,001 1,991 1,981 1,971 1,961 1,951 1,942 1,932
13…Small Part of Western Area Power Association Hydroelectric 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000 5,000
13 Total energy from RPSeligible resources (sum of 13a…13n, and 13z) 553,984 532,171 530,582 529,489 572,668 543,350 541,370 539,743 537,511 528,123 524,782 493,034 445,156 420,115
13z Undelivered RPS energy 279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885
14 Total energy from existing and planned supply resources (12+13) 1,336,540 1,036,355 1,055,794 1,046,970 1,068,625 1,039,307 1,037,327 1,035,700 1,033,468 1,024,080 1,020,739 988,991 941,114 916,073
GENERIC ADDITIONS
NONRPS ELIGIBLE RESOURCES:
[list resource by name or description]2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
15a
15 Total energy from generic supply resources (not RPSeligible)000000000000
RPSELIGIBLE RESOURCES:
[list resource by name or description]
16a
16e
16 Total energy from generic RPSeligible resources 000000000000
17 Total energy from generic supply resources (15+16)000000000000
17z Total energy from RPSeligible shortterm contracts
ENERGY FROM SHORTTERM PURCHASES
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
18 Short term and spot market purchases:81,940 79,524 154,110 182,370 160,888 170,642 172,094 173,495 177,953 184,029 188,028 207,719 239,323 258,553
ENERGY BALANCE SUMMARY
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
19 Total energy from supply resources (14+17+17z)1,336,540 1,036,355 1,055,794 1,046,970 1,068,625 1,039,307 1,037,327 1,035,700 1,033,468 1,024,080 1,020,739 988,991 941,114 916,073
19a Undelivered RPS energy (from 13z)279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885
20 Short term and spot market purchases (from 18)81,940 79,524 154,110 182,370 160,888 170,642 172,094 173,495 177,953 184,029 188,028 207,719 239,323 258,553
21 Total delivered energy (1919a+20)1,138,833 935,349 923,253 949,255 945,624 942,548 941,081 940,236 947,485 947,643 947,840 948,459 949,074 950,741
22 Total net energy for load (from 7)941,423 941,423 941,423 938,410 934,782 932,532 931,063 930,216 930,201 930,358 930,553 931,173 931,787 933,453
23 Surplus/Shortfall (2122)197,409 (6,075) (18,170)10,845 10,842 10,016 10,018 10,020 17,284 17,286 17,287 17,287 17,287 17,288
Historical Data
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Section XI: Appendices
XI—22
GHG Emissions Accounting Table (GEAT) iii.
State of California
California Energy Commission
Standardized Reporting Tables for Public Owned Utility IRP Filing
GHG Emissions Accounting Table
Form CEC 111 (May 2017)
Scenario Name: Expected
Yellow fill relates to an application for confidentiality.
Emissions Intensity Units = mt CO2e/MWhGHG EMISSIONS FROM EXISTING AND PLANNED SUPPLY RESOURCES Yearly Emissions Total Units = Mmt CO2e
UtilityOwned Generation (not RPSeligible):
[list resource by name] Emissions Intensity 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
1a #REF!0 000000000000
LongTerm Contracts (not RPSeligible):
[list contracts by name] Emissions Intensity
1h Western Base Resource Generation 0 000000000000
1n
1 Total GHG emissions of existing and planned supply resources (not RPS
eligible) (sum of 1a…1n)00000000000000
UtilityOwned RPSeligible Generation Resources:
[list resource by plant or unit] Emissions Intensity
2a New Spicer Hydroelectric 0 000000000000
LongTerm Contracts (RPSeligible):
[list contracts by name] Emissions Intensity
2h PROJECT #1 - HIGHWINDS 0
2i PROJECT #2 - SHILOH #1 0
2j Santa Cruz (Buena Vist Landfill)0
2k Ox Mountain (Half Moon Bay)0
2l Keller Canyon 0
2m Johnson Canyon (Ameresco)0
2n San Joaquin (Ameresco)0
2…EE Kettleman Land 0
2…Elevation Solar C 0
2…Western Antelope Blue Sky Ranch B 0
2…Frontier Solar 0
2…Hayworth Solar 0
2…Wilsona Solar 0
2…Palo Alto CLEAN Projects 0
2…Small Part of Western Area Power Association 0
2 Total GHG emissions from RPSeligible resources (sum of 2a…2n) 00000000000000
3 Total GHG emissions from existing and planned supply resources (1+2) 0 0 0 0 0 0 0 0 0 0 0 0 0 0
EMISSIONS FROM GENERIC ADDITIONS
NONRPS ELIGIBLE RESOURCES:
[list resource by name or description] Emissions Intensity 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
4a
4b
4 Total GHG emissions from generic supply resources (not RPSeligible)000000000000
RPSELIGIBLE RESOURCES:
[list resource by name or description] Emissions Intensity
5a
5b
5 Total GHG emissions from generic RPSeligible resources 000000000000
6 Total GHG emissions from generic supply resources (4+5)000000000000
GHG EMISSIONS OF SHORT TERM PURCHASES
Emissions Intensity 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
7 Short term and spot market purchases:0.428 35,070 34,036 65,959 78,054 68,860 73,035 73,656 74,256 76,164 78,764 80,476 88,904 102,430 110,661
TOTAL GHG EMISSIONS
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
8 Total GHG emissions to meet net energy for load (3+6+7) 35,070 34,036 65,959 78,054 68,860 73,035 73,656 74,256 76,164 78,764 80,476 88,904 102,430 110,661
EMISSIONS ADJUSTMENTS
8a Undelivered RPS energy (MWh from EBT)279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885
8b Firm Sales Obligations (MWh from EBT)00000000000000
8c Total energy for emissions adjustment (8a+8b)279,647 180,530 286,651 280,085 283,889 267,401 268,341 268,959 263,937 260,465 260,927 248,251 231,363 223,885
8d Emissions intensity (portfolio gas/shortterm and spot market purchases)0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428 0.428
8e Emissions adjustment (8Cx8D)119,689 77,267 122,687 119,877 121,505 114,448 114,850 115,114 112,965 111,479 111,677 106,251 99,023 95,823
PORTFOLIO GHG EMISSIONS
8f Portfolio emissions (88e)-84,619 -43,231 -56,728 -41,822 -52,645 -41,413 -41,193 -40,859 -36,801 -32,715 -31,201 -17,348 3,407 14,838
GHG EMISSIONS IMPACT OF TRANSPORTATION ELECTRIFICATION
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
9 GHG emissions reduction due to gasoline vehicle displacement by LD PEVs 0.02 0.03 0.04 0.04 0.04 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05 0.05
10 GHG emissions increase due to LD PEV electricity loads 00000000000000
11 GHG emissions reduction due to fuel displacement other transportation
electrification
12 GHG emissions increase due to increased electricity loads other
transportation electrification 00000000000000
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