12-01-15 Searchable packetCITY OF CUPERTINO
AGENDA
Tuesday, December 1, 2015
10350 Torre Avenue, Council Chamber
CITY COUNCIL
6:45 PM
PLEDGE OF ALLEGIANCE
ROLL CALL
CEREMONIAL MATTERS AND PRESENTATIONS
1.Subject: Update from Teen Commission
Recommended Action: Receive update
2.Subject: Update from Fine Arts Commission
Recommended Action: Receive update
POSTPONEMENTS
ORAL COMMUNICATIONS
This portion of the meeting is reserved for persons wishing to address the council on
any matter not on the agenda. Speakers are limited to three (3) minutes. In most cases,
State law will prohibit the council from making any decisions with respect to a matter
not listed on the agenda.
CONSENT CALENDAR
Unless there are separate discussions and/or actions requested by council, staff or a
member of the public, it is requested that items under the Consent Calendar be acted on
simultaneously.
3.Subject: Approve the November 17 City Council minutes
Recommended Action: Approve the minutes
A - Draft Minutes
4.Subject: Accept Accounts Payable for the period ending October 23, 2015
Recommended Action: Adopt Resolution No. 15-105 accepting Accounts Payable
for the period ending October 23, 2015
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December 1, 2015City Council AGENDA
A - Draft Resolution
B - AP Report
5.Subject: Accept Accounts Payable for the period ending October 30, 2015
Recommended Action: Adopt Resolution No. 15-106 accepting Accounts Payable
for the period ending October 30, 2015
A - Draft Resolution
B - AP Report
6.Subject: Accept Accounts Payable for the period ending November 6, 2015
Recommended Action: Adopt Resolution No. 15-107 accepting Accounts Payable
for the period ending November 6, 2015
A - Draft Resolution
B - AP Report
7.Subject: California State Law AB1717, Local Prepaid Mobile Telephony
Services Collection Act, effective January 1, 2016
Recommended Action: a.) Adopt Resolution No. 15-108 authorizing the City
Manager to Execute the Agreement with the State Board of Equalization; and b.)
Adopt Resolution No. 15-109 authorizing the Examination for the Prepaid Mobile
Telephony Services Surcharge and Local Charge Records
Staff Report
A - Draft Resolution Agreement with the State Board of Equalization
B - Draft Resolution Prepaid Mobile Telephony Services Surcharge
C - Local Charge Agreement
8.Subject: Letter to President Obama expressing support for the Clean Power Plan
and transitioning U.S. energy consumption to 100% renewable by 2050.
Recommended Action: Authorize the Mayor to sign a letter to President Obama in
support of the Clean Power Plan and transitioning the nation’s energy consumption
to be 100% renewable by 2050.
Staff Report
A - Letter of Support
9.Subject: Participate in the Compact of Mayors by sending a letter of commitment
to the Compact of Mayors Secretariat.
Recommended Action: Authorize the Mayor to sign the letter of commitment to the
Compact of Mayors, joining coalitions of mayors and city officials worldwide
committing to reduce local greenhouse gas emissions and enhance resilience to
climate change.
Staff Report
A - Letter of Intent
10.Subject: Participation in the Institute for Local Government’s Beacon Award:
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December 1, 2015City Council AGENDA
Local Leadership toward Solving Climate Change Recognition Program
Recommended Action: Adopt Resolution 15-110 supporting the City’s participation
in the Institute for Local Government’s Beacon Award: Local Leadership toward
Solving Climate Change Recognition Program.
Staff Report
A - Resolution
11.Subject: Declare weeds a nuisance and set hearing date of January 19 for
objections to proposed removal
Recommended Action: Adopt Resolution No. 15-112 declaring weeds a nuisance
and setting hearing date of January 19 for objections to proposed removal
Staff Report
A - Draft Resolution
12.Subject: Blackberry Farm Golf Course Maintenance Agreement, Contract Award
Recommended Action: Authorize the City Manager to award, negotiate and execute
a contract with Professional Turf Management of San Jose, California in the amount
of $99,600, as selected through a Request for Qualification process, and further
authorize the City Manager to execute annual extensions to the contract for up to five
years based upon the pricing in the bid documents, subject to appropriation
Staff Report
A - Draft Contract
13.Subject: Application for Alcoholic Beverage License for Yayoi, 20682 & 20684
Homestead Road
Recommended Action: Recommend approval of the Alcoholic Beverage License to
the California Department of Alcoholic Beverage Control for Yayoi, 20682 & 20684
Homestead Road
Staff Report
A - Application
14.Subject: Application for Alcoholic Beverage License for Pieology Pizzeria, 19409
Stevens Creek Boulevard, Suite 140
Recommended Action: Recommend approval of the Alcoholic Beverage License to
the California Department of Alcoholic Beverage Control for Pieology Pizzeria,
19409 Stevens Creek Boulevard, Suite 140
Staff Report
A - Application
15.Subject: Application for Alcoholic Beverage License for Tofu Plus, 10971 North
Wolfe Road
Page 3 CITY OF CUPERTINO
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December 1, 2015City Council AGENDA
Recommended Action: Recommend approval of the Alcoholic Beverage License to
the California Department of Alcoholic Beverage Control for Tofu Plus, 10971
North Wolfe Road
Staff Report
A - Application
16.Subject: Application for Alcoholic Beverage License for Starbucks #5217, 20520
Stevens Creek Boulevard
Recommended Action: Recommend approval of the Alcoholic Beverage Control
License to the California Department of Alcoholic Beverage Control for Starbucks
#5217, 20520 Stevens Creek Boulevard
Staff Report
A - Application
17.Subject: Application for Alcoholic Beverage License for Yoshida Restaurant,
10700 South De Anza Boulevard
Recommended Action: Recommend approval of the Alcoholic Beverage License to
the California Department of Alcoholic Beverage Control for Yoshida Restaurant,
10700 South De Anza Boulevard
Staff Report
A - Application
SECOND READING OF ORDINANCES
18.Subject: Second reading of an Ordinance amending Section 2.04.010 of the
Cupertino Municipal Code regarding regular City Council meetings that fall on
any Election Tuesday in a regular Cupertino election year
Recommended Action: Conduct the second reading and enact Ordinance No.
15-2137: "An Ordinance of the City Council of the City of Cupertino amending
Section 2.04.010 of Chapter 2.04 of Title 2 of the Cupertino Municipal Code
regarding regular City Council meetings that fall on any Election Tuesday in a
regular Cupertino election year"
Staff Report
A - Redline Draft Ordinance
B - Clean Draft Ordinance
PUBLIC HEARINGS
ORDINANCES AND ACTION ITEMS
19.Subject: Approve actions related to the formation of, and Cupertino’s
membership in, the Silicon Valley Clean Energy Authority, an independent joint
powers authority, which will provide a Community Choice Aggregation Program
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December 1, 2015City Council AGENDA
to offer clean energy alternatives for Cupertino residents and businesses; and
related CEQA action
Recommended Action: 1.Accept the Silicon Valley Community Choice Energy
Technical Study Draft Report, and find that the proposed actions are exempt from
CEQA; and
2.Conduct the first reading of the Ordinance No. 15-2138: “An Ordinance of the
City Council of the City of Cupertino Authorizing the Implementation of a
Community Choice Aggregation Program” to create and participate in the Silicon
Valley Clean Energy Authority; and
3.Adopt Resolution No. 15-111 of the City Council of the City of Cupertino
Approving the Joint Powers Agreement Establishing the Silicon Valley Clean
Energy Authority; and
4.Authorize the City Manager to remit up to $450,000, as previously budgeted, to
the Silicon Valley Clean Energy Authority to support the initial costs of the
Authority; and
5.Approve an increase to the Fiscal Year 2015-16 Sustainability Division Special
Project Budget of $100,000 for project contingency as outlined in the JPA; and
6.Direct staff to return to Council with an update and potential action regarding
bridge financing for the Authority; and
7.Direct staff to return to Council with a proposal to provide interim project and/or
staffing support to the Authority via a separate services agreement; and
8.Direct staff to return to Council for appointment of a regular Director and
alternate Director to the Authority’s Board of Directors.
Staff Report
A - Technical Study Draft Report
B - Community Choice Energy Draft Ordinance
C - Joint Powers Authority Draft Resolution
D - Joint Powers Authority Draft Agreement
REPORTS BY COUNCIL AND STAFF
ELECTION OF MAYOR AND VICE MAYOR
20.Subject: Council members elect Mayor
Recommended Action: Make nominations and elect Mayor
21.Subject: Council members elect Vice Mayor
Recommended Action: Make nominations and elect Vice Mayor
OATH OF OFFICE
22.Subject: Mayor takes Oath of Office
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December 1, 2015City Council AGENDA
Recommended Action: Mayor takes Oath of Office
23.Subject: Vice Mayor takes Oath of Office
Recommended Action: Vice Mayor takes Oath of Office
COMMENTS BY NEW MAYOR
24.Subject: Comments by new Mayor and presentation of gifts
Recommended Action: Comments by new Mayor and presentation of gifts
COMMENTS BY COUNCIL MEMBERS AND PUBLIC
25.Subject: Comments by Council members
Recommended Action: Comments by Council members
26.Subject: Members of the audience are invited to speak
Recommended Action: Members of the audience are invited to speak
RECEPTION
27.Subject: The public is invited to attend a reception in the lobby
Recommended Action: The public is invited to attend a reception in the lobby
ADJOURNMENT
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December 1, 2015City Council AGENDA
The City of Cupertino has adopted the provisions of Code of Civil Procedure §1094.6;
litigation challenging a final decision of the City Council must be brought within 90
days after a decision is announced unless a shorter time is required by State or Federal
law.
Prior to seeking judicial review of any adjudicatory (quasi-judicial) decision, interested
persons must file a petition for reconsideration within ten calendar days of the date the
City Clerk mails notice of the City’s decision. Reconsideration petitions must comply
with the requirements of Cupertino Municipal Code §2.08.096. Contact the City Clerk’s
office for more information or go to http://www.cupertino.org/index.aspx?page=125 for
a reconsideration petition form.
In compliance with the Americans with Disabilities Act (ADA), anyone who is planning
to attend the next City Council meeting who is visually or hearing impaired or has any
disability that needs special assistance should call the City Clerk's Office at
408-777-3223, 48 hours in advance of the Council meeting to arrange for assistance.
Upon request, in advance, by a person with a disability, City Council meeting agendas
and writings distributed for the meeting that are public records will be made available
in the appropriate alternative format. Also upon request, in advance, an assistive
listening device can be made available for use during the meeting.
Any writings or documents provided to a majority of the Cupertino City Council after
publication of the packet will be made available for public inspection in the City
Clerk’s Office located at City Hall, 10300 Torre Avenue, during normal business hours
and in Council packet archives linked from the agenda/minutes page on the Cupertino
web site.
Members of the public are entitled to address the City Council concerning any item that
is described in the notice or agenda for this meeting, before or during consideration of
that item. If you wish to address the Council on any issue that is on this agenda, please
complete a speaker request card located in front of the Council, and deliver it to the
Clerk prior to discussion of the item. When you are called, proceed to the podium and
the Mayor will recognize you. If you wish to address the City Council on any other item
not on the agenda, you may do so by during the public comment portion of the meeting
following the same procedure described above. Please limit your comments to three (3)
minutes or less.
Page 7 CITY OF CUPERTINO
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1139 Name:
Status:Type:Ceremonial Matters &Presentations Agenda Ready
File created:In control:10/5/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Update from Teen Commission
Sponsors:
Indexes:
Code sections:
Attachments:
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Update from Teen Commission
Receive update
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1140 Name:
Status:Type:Ceremonial Matters &Presentations Agenda Ready
File created:In control:10/5/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Update from Fine Arts Commission
Sponsors:
Indexes:
Code sections:
Attachments:
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Update from Fine Arts Commission
Receive update
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-0700 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:2/18/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Approve the November 17 City Council minutes
Sponsors:
Indexes:
Code sections:
Attachments:A - Draft Minutes
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Approve the November 17 City Council minutes
Approve the minutes
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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DRAFT MINUTES
CUPERTINO CITY COUNCIL
Tuesday, November 17, 2015
SPECIAL CITY COUNCIL MEETING
ROLL CALL
At 5:35 p.m. Mayor Rod Sinks called the Special City Council meeting to order in Cupertino
City Hall Conference Room A, 10300 Torre Avenue.
ROLL CALL
Present: Mayor Rod Sinks, Vice Mayor Barry Chang and Council members Savita
Vaidhyanathan, Darcy Paul (5:55 p.m.) and Gilbert Wong. Absent: None.
At 5:35 p.m. Council went into closed session and reconvened in open session at 6:45 p.m. in
the Cupertino Community Hall Council Chamber, 10350 Torre Avenue.
CLOSED SESSION
1. Subject: Conference with Labor Negotiators (54957.6). Agency designated
representatives: Assistant to the City Manager and Jaime Bodiford. Appointed
employee: City Manager
Mayor Sinks announced that Council provided direction to staff.
2. Subject: Conference with Legal Counsel - Anticipated Litigation: Significant exposure
to litigation pursuant to paragraph (2) of subdivision (d) of Government Code Section
54956.9 - One case
Mayor Sinks announced that Council provided direction to staff and legal counsel.
3. Subject: Conference with Real Property Negotiators (Government Code 54956.8).
Property: Cupertino Municipal Water System. Agency Negotiator: Timm Borden.
Negotiating Parties: City of Cupertino and San Jose Water Company. Under
Negotiation: Terms for City Leased Asset
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City Council Minutes November 17, 2015
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Mayor Sinks announced that Council provided direction to staff and legal counsel.
4. Subject: Conference with Legal Counsel - Anticipated Litigation: Initiation of litigation
pursuant to paragraph (4) of subdivision (d) of Government Code Section 54956.9 - One
case
Mayor Sinks announced that Council provided direction to staff and legal counsel.
ADJOURNMENT
REGULAR CITY COUNCIL MEETING
PLEDGE OF ALLEGIANCE
At 6:45 p.m. Mayor Rod Sinks called the Regular City Council meeting to order in Cupertino
Community Hall Council Chambers, 10350 Torre Avenue and led the Pledge of Allegiance.
ROLL CALL
Present: Mayor Rod Sinks, Vice Mayor Barry Chang and Council members Savita
Vaidhyanathan, Darcy Paul and Gilbert Wong. Absent: None.
STUDY SESSION
1. Subject: Study Session on the Civic Center Master Plan - Financing Alternatives and
Affordability Analysis
Recommended Action: Receive staff presentation and provide direction
Written communications for this item included emails to Council and a staff
PowerPoint presentation.
Director of Public Works Timm Borden, Finance Manager Lisa Taitano, and City
Manager David Brandt reviewed the staff report via a PowerPoint presentation. Also
present was Peter Rossi from Rossi Financial who prepared the financial plans.
Mr. Borden noted one correction to the report in the packet. Support for option 4 –
perch expansion was Library staff and the Cupertino Library Commission.
Staff and Mr. Rossi answered questions from Council.
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City Council Minutes November 17, 2015
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The following individuals spoke on this item:
Cathy Helgerson
Peggy Griffin
Liang Chao
Their comments included: concern over adding additional debt and what would have
to be given up; renovate rather than build new; no need for Emergency Operations
Center and no underground parking; bring bond measure to the voters; be creative
with financing; cost is too high and go out to bid; conflict of interest with Perkins +
Will; money from developers shouldn’t be earmarked for City Hall.
Council gave the following direction to staff:
Explore options for cost of $40 million (financed plus cash)
Explore option of leasing 40,000 square feet
Explore possibility of building proposed project for half the cost
Council recessed from 8:51 p.m. to 9:02 p.m.
CEREMONIAL MATTERS AND PRESENTATION
2. Subject: Update from the Housing Commission
Recommended Action: Receive update
Written communications for this item included a PowerPoint presentation.
Vice Chair of the Housing Commission Harvey Barnett gave an update on the
Commission via a PowerPoint presentation.
Cathy Helgerson talked about the waiting list for affordable housing and would like to
see subsidies given to teachers who want to live in Cupertino and to students who can’t
afford rental housing.
Council received the update.
3. Subject: Update from the Planning Commission
Recommended Action: Receive the update
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City Council Minutes November 17, 2015
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Written communications for this item included a PowerPoint presentation.
Chair of the Planning Commission and Commissioner Geoff Paulsen gave an update
on the Commission via a PowerPoint presentation.
Council received the update.
POSTPONEMENTS - None
ORAL COMMUNICATIONS
Mike Rhode on behalf of the Vallco Shopping Mall property owner talked about their leasing
operation and notice given to the tenants as they prepare for changes to the mall.
Lisa Warren talked about a letter of intent with Sand Hill Property Company and the
Cupertino Union School District. She distributed a hard copy of the letter.
Cathy Helgerson talked about the small business owners in Vallco being asked to relocate.
Moe Satter small business owner in Vallco talked about being asked to relocate.
A.J. small business owner in Vallco talked about being asked to relocate.
Israv Khen General Manager at a small business in Vallco talked about the business being
asked to relocate.
Surinder Kaur small business owner in Vallco talked about being asked to relocate. She
distributed written comments.
Takken Tru talked about the Vallco Mall project.
David Chang small business owner in Vallco Mall talked about being asked to relocate.
Kim Chi Vo small business owner in Vallco Mall talked about being asked to relocate.
Liang-Fang Chao talked about the small business owners in Vallco Mall who are being asked
to relocate.
Osman Khan small business owner in Vallco Mall talked about being asked to relocate.
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City Council Minutes November 17, 2015
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CONSENT CALENDAR
Wong moved and Vaidhyanathan seconded to approve the items on the Consent Calendar as
presented with the exception of item numbers 9 and 10 which were pulled for discussion.
Ayes: Sinks, Chang, Paul, Vaidhyanathan and Wong. Noes: None. Abstain: None. Absent:
None.
4. Subject: Approve the November 3 City Council minutes
Recommended Action: Approve the minutes
5. Subject: Approve Treasurer's Investment Report for the Quarter ending June 30,
Recommended Action: Accept the report
6. Subject: Approve Treasurer's Investment Report for the Quarter ending September 30,
2015
Recommended Action: Accept the report
7. Subject: Approval of the First Quarter adjustments for Fiscal Year 2015-16 as described
in the First Quarter Financial Report
Recommended Action: 1. Accept the City Manager's First Quarter Financial Report for
Fiscal Year 2015-16; and 2. Adopt Resolution No. 15-100 approving the First Quarter
budget adjustments
8. Subject: A resolution to allow the use of electronic signatures (E-signatures) on City
documents
Recommended Action: Staff recommends that the City Council adopt Resolution No.
15-101 to allow the use of electronic signatures (E-signatures) on applicable City
documents
9. Subject: Approve the Employment Contract for the City Manager, and amend the
Appointed Employees’ Compensation Program
Recommended Action: a.) Adopt Resolution No. 15-102 approving the Third
Amendment to the Employment Contract for the City Manager; and b.) Adopt
Resolution No. 15-103 amending the Appointed Employees’ Compensation Program
a.) Adopted Resolution No. 15-102 approving the Third Amendment to the
Employment Contract for the City Manager as amended to make the new
compensation retroactive closest to the City Manager’s annual employment date of
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City Council Minutes November 17, 2015
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September 9; and b.) Adopted Resolution No. 15-103 amending the Appointed
Employees’ Compensation program. The motion carried unanimously.
10. Subject: Amendment to an existing consultant services agreement with David J. Powers
and Associates for environmental review for a Specific Plan and project in the Vallco
Shopping District Planning Area for a total contract in the amount of $919,245, and
authorization for further amendments.
Recommended Action: 1. Authorize an amendment to the existing “Agreement
between the City of Cupertino and David J. Powers & Associates, Inc for the CEQA
Environmental Review for the Vallco Specific Plan Redevelopment Project” consultant
services agreement with David J. Powers and Associates, Inc. (DJP&A) for preparation
of an Environmental Impact Report (EIR) for the Council’s consideration, for an
additional amount not to exceed $164,940, for a total cost of $919,245. (Attachment A).
2. Authorize the City Manager to negotiate and execute additional future amendments
to Item 1 above to the extent that funds are appropriated for the amendments and the
total expenditures are cost-recovered from the applicant. 3. Approve an increase to the
Fiscal Year 2015-16 Planning and Community Development-Mid to Long Term
Planning program budget of $181,434 ($164,940 plus 10% administrative fee)
Cathy Helgerson talked about the amount of money being spent on consultants and to
pay attention to the EIR comments from residents.
Peggy Griffin talked about the Vallco project and encouraged Council to vote no on
item 2 under the recommended action.
Paul moved and Chang seconded to 1. Authorize an amendment to the existing
“Agreement between the City of Cupertino and David J. Powers & Associates, Inc. for
the CEQA Environmental Review for the Vallco Specific Plan Redevelopment Project”
consultant services agreement with David J. Powers and Associates, Inc. (DJP&A) for
preparation of an Environmental Impact Report (EIR) for the Council’s consideration,
for an additional amount not to exceed $164,940, for a total cost of $919,245.
(Attachment A). 2. Did not authorize the City Manager to negotiate and execute
additional future amendments to Item 1 above to the extent that funds are
appropriated for the amendments and the total expenditures are cost-recovered from
the applicant (any amendments will come back to Council). 3. Approved an increase to
the Fiscal Year 2015-16 Planning and Community Development-Mid to Long Term
Planning program budget of $181,434 ($164,940 plus 10% administrative fee). The
motion carried with Sinks voting no.
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City Council Minutes November 17, 2015
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11. Subject: Amendment to increase City funding for the Memorandum of Understanding
(MOU) (Attachment A) with the Santa Clara Valley Water District (District) for their
Landscape Conversion Rebate Program (Program)
Recommended Action: Staff recommends Council adopt Resolution No. 15-104
amending Approved FY 15/16 Operating Budget (Attachment B) and Authorize the
City Manager to execute an amendment to the MOU with the District in an increased
amount of up to $115,000 to supplement the District’s Program for the benefit of
Cupertino residents and businesses
12. Subject: 2016 Pavement Maintenance Project, Project No. 2016-15 authority to award
contract
Recommended Action: Authorize the City Manager to award and execute the 2016
Pavement Maintenance Project contract, including a 10% contingency, if the lowest
responsive bid is within the established budget and there are no unresolved bid
protests
13. Subject: Funding agreement between the City of Cupertino and the Santa Clara Valley
Transportation Authority (VTA) for the I-280/Wolfe Road Interchange Improvements
Project
Recommended Action: Authorize the City Manager to negotiate and execute a Funding
Agreement with the VTA to identify the City of Cupertino and VTA’s respective
obligations for the I-280/Wolfe Road Interchange Improvements Project to the extent
that the City of Cupertino’s contributions are expected to be reimbursed from project
applicants and funds are appropriated for such purpose
SECOND READING OF ORDINANCES
14. Subject: Second reading of Ordinance and adopt amendments to the City's Zoning Map
to rezone a 0.98 acre parcel from Light Industrial with Special Development Conditions
(ML-fa) to Planned Development Zoning District with Light Industrial And
Commercial Uses P(ML, CG)). (Z-2015-01, 10950 N. Blaney Avenue, APN: 316 03 041)
Recommended Action: Conduct the second reading and enact Ordinance No. 15-2135:
“An Ordinance of the City Council of the City of Cupertino rezoning a 0.98 acre parcel
from Light Industrial with Special Development Conditions (ML-fa) to Planned
Development Zoning District with Light Industrial And Commercial Uses P(ML, CG)"
City Clerk Grace Schmidt read the title of the ordinance.
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City Council Minutes November 17, 2015
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Chang moved and Paul seconded to read Ordinance No. 15-2135 by title only and that
the City Clerk’s reading would constitute the second reading thereof. Ayes: Sinks,
Chang, Paul, Vaidhyanathan and Wong. Noes: None. Abstain: None. Absent: None.
Chang moved and Vaidhyanathan seconded to enact Ordinance No. 15-2135. Ayes:
Sinks, Chang, Paul, Vaidhyanathan and Wong. Noes: None. Abstain: None. Absent:
None.
15. Subject: Second reading of ordinance amending Section 2.12.040 of the Cupertino
Municipal Code to clarify the number of votes required to pass ordinances, resolutions,
and certain orders to ensure that the Municipal Code is consistent with State Law
Recommended Action: Conduct the second reading and enact Ordinance No. 15-2136:
An Ordinance of the City Council of the City of Cupertino amending Section 2.12.040
of the Cupertino Municipal Code regarding the number of votes required for
Ordinances, Resolutions, and Certain Orders
City Clerk Grace Schmidt read the title of the ordinance.
Chang moved and Paul seconded to read Ordinance No. 15-2136 by title only and that
the City Clerk’s reading would constitute the second reading thereof. Ayes: Sinks,
Chang, Paul, Vaidhyanathan and Wong. Noes: None. Abstain: None. Absent: None.
Chang moved and Vaidhyanathan seconded to enact Ordinance No. 15-2136. Ayes:
Sinks, Chang, Paul, Vaidhyanathan and Wong. Noes: None. Abstain: None. Absent:
None.
PUBLIC HEARINGS - None
ORDINANCES AND ACTION ITEMS
16. Subject: First reading of an Ordinance amending Section 2.04.010 of the Cupertino
Municipal Code regarding regular City Council meetings that fall on Election Tuesday
in even-numbered years
Recommended Action: Conduct the first reading Ordinance No. 15-2137: “An
Ordinance of the City Council of the City of Cupertino amending Section 2.04.010 of
Chapter 2.04 of Title 2 of the Cupertino Municipal Code regarding regular City Council
meetings that fall on Election Tuesday in even-numbered years"
City Clerk Grace Schmidt reviewed the staff report.
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City Council Minutes November 17, 2015
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Council amended the ordinance language to read: City Council meetings that fall on
any Election Tuesday in a regular Cupertino election year shall automatically be moved
to the first Monday of the month.
City Clerk Grace Schmidt read the title of the ordinance.
Chang moved and Wong seconded to read Ordinance No. 15-2137 as amended by title
only and that the City Clerk’s reading would constitute the first reading thereof Ayes:
Sinks, Chang, Paul, Vaidhyanathan and Wong. Noes: None. Abstain: None. Absent:
None.
REPORTS BY COUNCIL AND STAFF
17. Subject: Report on Committee assignments and general comments
Recommended Action: Report on Committee assignments and general comments
City Manager David Brandt talked about the issue with the Vallco small business
owners and noted that the City’s Economic Development Manager has met with some
of the owners. The City will continue to try and work with them regarding relocation.
Council members highlighted the activities of their committees and various
community events.
ADJOURNMENT
At 11:10 p.m., Mayor Sinks adjourned the meeting to Tuesday, December 1.
_______________________________
Grace Schmidt, City Clerk
Staff reports, backup materials, and items distributed at the City Council meeting are
available for review at the City Clerk’s Office, 777-3223, and also on the Internet at
www.cupertino.org. Click on Agendas & Minutes, then click on the appropriate Packet.
Most Council meetings are shown live on Comcast Channel 26 and AT&T U-verse Channel 99
and are available at your convenience at www.cupertino.org. Click on Agendas & Minutes,
and then click Archived Webcast. Videotapes are available at the Cupertino Library, or may
be purchased from the Cupertino City Channel, 777-2364.
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1223 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/16/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Accept Accounts Payable for the period ending October 23, 2015
Sponsors:
Indexes:
Code sections:
Attachments:A - Draft Resolution
B - AP Report
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Accept Accounts Payable for the period ending October 23, 2015
AdoptResolutionNo.15-105acceptingAccountsPayablefortheperiodendingOctober23,
2015
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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RESOLUTION NO.
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF
CUPERTINO ALLOWING CERTAIN CLAIMS AND DEMANDS PAYABLE IN
THE AMOUNTS AND FROM THE FUNDS AS HEREINAFTER DESCRIBED
FOR GENERAL AND MISCELLANEOUS EXPENDITURES FOR THE PERIOD
ENDING
October 23, 2015
WHEREAS, the Director of Administrative Services or her designated
representative has certified to accuracy of the following claims and demands and
to the availability of funds for payment hereof; and
WHEREAS, the said claims and demands have been audited as required
by law.
NOW, THEREFORE, BE IT RESOLVED, that the City Council hereby
allows the following claims and demands in the amounts and from the funds as
hereinafter set forth in the attached Payment Register.
CERTIFIED: _____________________________
Lisa Taitano, Finance Manager
PASSED AND ADOPTED at a regular meeting of the City Council of the
City of Cupertino this 1st day of December, 2015, by the following vote:
Vote Members of the City Council
AYES:
NOES:
ABSENT:
ABSTAIN:
ATTEST: APPROVED:
_________________________ ________________________
Grace Schmidt, City Clerk Rod Sinks, Mayor, City of Cupertino
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1224 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/16/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Accept Accounts Payable for the period ending October 30, 2015
Sponsors:
Indexes:
Code sections:
Attachments:A - Draft Resolution
B - AP Report
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Accept Accounts Payable for the period ending October 30, 2015
AdoptResolutionNo.15-106acceptingAccountsPayablefortheperiodendingOctober30,
2015
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™42
RESOLUTION NO.
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF
CUPERTINO ALLOWING CERTAIN CLAIMS AND DEMANDS PAYABLE IN
THE AMOUNTS AND FROM THE FUNDS AS HEREINAFTER DESCRIBED
FOR GENERAL AND MISCELLANEOUS EXPENDITURES FOR THE PERIOD
ENDING
October 30, 2015
WHEREAS, the Director of Administrative Services or her designated
representative has certified to accuracy of the following claims and demands and
to the availability of funds for payment hereof; and
WHEREAS, the said claims and demands have been audited as required
by law.
NOW, THEREFORE, BE IT RESOLVED, that the City Council hereby
allows the following claims and demands in the amounts and from the funds as
hereinafter set forth in the attached Payment Register.
CERTIFIED: _____________________________
Lisa Taitano, Finance Manager
PASSED AND ADOPTED at a regular meeting of the City Council of the
City of Cupertino this 1st day of December, 2015, by the following vote:
Vote Members of the City Council
AYES:
NOES:
ABSENT:
ABSTAIN:
ATTEST: APPROVED:
_________________________ ________________________
Grace Schmidt, City Clerk Rod Sinks, Mayor, City of Cupertino
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1225 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/16/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Accept Accounts Payable for the period ending November 6, 2015
Sponsors:
Indexes:
Code sections:
Attachments:A - Draft Resolution
B - AP Report
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Accept Accounts Payable for the period ending November 6, 2015
AdoptResolutionNo.15-107acceptingAccountsPayablefortheperiodendingNovember6,
2015
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™60
RESOLUTION NO.
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF
CUPERTINO ALLOWING CERTAIN CLAIMS AND DEMANDS PAYABLE IN
THE AMOUNTS AND FROM THE FUNDS AS HEREINAFTER DESCRIBED
FOR GENERAL AND MISCELLANEOUS EXPENDITURES FOR THE PERIOD
ENDING
November 06, 2015
WHEREAS, the Director of Administrative Services or her designated
representative has certified to accuracy of the following claims and demands and
to the availability of funds for payment hereof; and
WHEREAS, the said claims and demands have been audited as required
by law.
NOW, THEREFORE, BE IT RESOLVED, that the City Council hereby
allows the following claims and demands in the amounts and from the funds as
hereinafter set forth in the attached Payment Register.
CERTIFIED: _____________________________
Lisa Taitano, Finance Manager
PASSED AND ADOPTED at a regular meeting of the City Council of the
City of Cupertino this 1st day of December, 2015, by the following vote:
Vote Members of the City Council
AYES:
NOES:
ABSENT:
ABSTAIN:
ATTEST: APPROVED:
_________________________ ________________________
Grace Schmidt, City Clerk Rod Sinks, Mayor, City of Cupertino
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:215-1146 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:10/6/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: California State Law AB1717, Local Prepaid Mobile Telephony Services Collection Act,effective January 1, 2016
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Draft Resolution Agreement with the State Board of Equalization
B - Draft Resolution Prepaid Mobile Telephony Services Surcharge
C - Local Charge Agreement
Action ByDate Action ResultVer.
City Council12/1/20152
Subject:CaliforniaStateLawAB1717,LocalPrepaidMobileTelephonyServicesCollection
Act, effective January 1, 2016
a.)AdoptResolutionNo.15-108authorizingtheCityManagertoExecutetheAgreementwith
theStateBoardofEqualization;andb.)AdoptResolutionNo.15-109authorizingthe
Examination for the Prepaid Mobile Telephony Services Surcharge and Local Charge Records
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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CITY MANAGER’S OFFICE
CITY HALL
10 10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3212 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
California state law AB 1717, Local Prepaid Mobile Telephony Services Collection Act,
effective January 1, 2016.
Recommended Action
a. Adopt the Draft Resolution authorizing the City Manager to Execute the
Agreement with the State Board of Equalization
b. Adopt the Draft Resolution authorizing the Examination for the Prepaid Mobile
Telephony Services Surcharge and Local Charge Records
Description
Governor Brown signed into law last year’s AB 1717, the Local Prepaid Mobile
Telephony Services Collection (MTS) Act. It requires retailers and phone carriers to
collect Utility Users Tax (UUT) on prepaid services beginning January 1, 2016. Retailers
must pay the local UUT to the State Board of Equalization (BOE), which will distribute
it to cities and counties quarterly, as it does sales and use tax.
Cupertino’s existing Telecommunication Users Tax code (Chapter 3.35) sufficiently
covers this new surcharge, so a change to the code is not necessary. The City does,
however, need to authorize the BOE to charge, collect, and examine records pertaining
to this new surcharge in order to effectively implement this legislation on behalf of the
City. The attached resolutions provide that authorization. Similar documents have
been executed with BOE to collect existing UUT for the City.
Sustainability Impact
There is no sustainability impact resulting from this action.
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Fiscal Impact
The prepaid MTS surcharge generally applies to amounts charged for:
prepaid wireless airtime cards
prepaid wireless cards compatible with pay-as-you-go cell phones
prepaid wireless minutes
prepaid wireless plans
prepaid wireless refill or top-off cards
prepaid wireless 'e-Cards'
prepaid mobile data or any other services when sold with any of the above
limited versions of bundled services sold with prepaid MTS.
The UUT rate specified in Cupertino's ordinance is 2.4% and applies to all City utility
taxes, including prepaid MTS. The City’s ordinance anticipated eventual approval of
this surcharge on prepaid MTS and was drafted accordingly. For this new surcharge
only, the current rate will be suspended and replaced by the applicable tiered rates
under the Local Prepaid Mobile Telephony Services Collection Act. For Cupertino, the
rate for prepaid MTS will be 1.5%. The full tiered chart is as follows:
UUT Rate in Ordinance New UUT Rate for Prepaid MTS
If less than 1.5 percent 0 percent
If 1.5 percent, but less than 2.5 percent 1.5 percent
If 2.5 percent, but less than 3.5 percent 2.5 percent
If 3.5 percent, but less than 4.5 percent 3.5 percent
If 4.5 percent, but less than 5.5 percent 4.5 percent
If 5.5 percent, but less than 6.5 percent 5.5 percent
If 6.5 percent, but less than 7.5 percent 6.5 percent
If 7.5 percent, but less than 9.0 percent 7.5 percent
If 9.0 percent or more 9.0 percent
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In a previous legal analysis performed for Cupertino when this legislation was being
proposed, the incremental revenue that prepaid MTS would constitute was projected to
be 20% of the total telecommunications market. In the following table, projected
incremental revenues are calculated using the lower rate of 1.5% (not 2.4%) and further
reduced by BOE administrative costs and a 3% vendor compensation cost.
Projected FY2016-17 Projected Out Years
1,536,505.91 Total Telecomm UUT 1,536,505.91 Total Telecomm UUT
192,063.24 20% of Total at 1.5% 192,063.24 20% of Total at 1.5%
(96,031.62) Less 50% BOE Admin (38,412.65) Less 20% BOE Admin
(5,761.90) Less 3% Vendor Commission (5,761.90) Less 3% Vendor Commission
$ 90,269.72 Incremental Revenue to City $ 147,888.69 Incremental Revenue to City
For the first year of full implementation, staff projects BOE Admin will be 50% and then
decline to 20% in the out years. BOE administrative cost estimates have not been made
and are expected to be posted to its website in December.
____________________________________
Prepared by: Lisa Taitano, Finance Manager
Reviewed and Approved for Submission by: David Brandt, City Manager
Attachments:
A: Draft Resolution Agreement with the State Board of Equalization
B: Draft Resolution Prepaid Mobile Telephony Services Surcharge
C: Local Charge Agreement
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RESOLUTION NO. ______________
A RESOLUTION OF THE CITY OF CUPERTINO
AUTHORIZING CITY MANAGER TO EXECUTE
AGREEMENT WITH THE STATE BOARD OF EQUALIZATION FOR IMPLEMENTATION
OF THE LOCAL PREPAID MOBILE TELEPHONY SERVICES COLLECTION ACT
WHEREAS, on December 1, 2015, the City Council certified that Ordinance No. 09-130 applies its
local charge(s) (access to 911 or communication services and/or utility user tax) to prepaid mobile
telephony services; and
WHEREAS, the Local Prepaid Mobile Telephony Services Collection Act, mandates the Board of
Equalization (Board) to administer and collect the local charges for all applicable local jurisdictions
(Rev. & Tax Code section 42103); and
WHEREAS, the Board will perform all functions incident to administration and collection of the local
charges for the City of Cupertino; and
WHEREAS, the Board requires that the City of Cupertino enter into an “Agreement for State
Collection and Administration of Local Charges” the Agreement prior to implementation of the Local
Prepaid Mobile Telephony Services Collection Act, and
Whereas, the Board requires that the City Manager authorize the agreement;
NOW, THEREFORE BE IT RESOLVED by the City Council that the attached “Agreement for State
Collection and Administration of Local Charges” is hereby approved and the City Manager is hereby
authorized to execute the Agreement and Certification of Rates and Ordinances.
* * * * * *
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The foregoing resolution was introduced and adopted at a regular meeting of the City Council held on
December 1st, 2015, by the following vote:
AYES:
NOES:
ABSENT:
DATED:
ATTEST: (s) (s)
(Printed Name & Title) (Signature)
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RESOLUTION NO.__________
A Resolution Authorizing the Examination of Prepaid Mobile Telephony Services Surcharge and
Local Charge Records
WHEREAS, pursuant to Ordinance No., ___________ of the City of _______________ and the Local
Prepaid Mobile Telephony Services Collection Act, the City of _________________, hereinafter called
Local Jurisdiction, entered into a contract with the State Board of Equalization, hereafter referred to as
the Board, to perform all functions incident to the administration and collection of the prepaid mobile
telephony services surcharge and local charges (Rev. & Tax. Code, § 42101.5); and
WHEREAS, the Local Jurisdiction deems it desirable and necessary for authorized representatives of
the Local Jurisdiction to examine confidential prepaid mobile telephony services surcharge and local
charge records pertaining to the prepaid mobile telephony services surcharge and local charges
collected by the Board for the Local Jurisdiction pursuant to that contract;
WHEREAS, the Board will make available to the Local Jurisdiction any information that is reasonably
available to the Board regarding the proper collection and remittance of a local charge of the Local
Jurisdiction by a seller, including a direct seller, subject to the confidentiality requirements of Sections
7284.6, 7284.7 and 19542 of the Revenue and Taxation Code; and
WHEREAS, Sections 42110 and 42103 of the Revenue and Taxation Code sets forth certain
requirements and conditions for the disclosure of Board of Equalization records and establishes
criminal penalties for the unlawful disclosure of information contained in or derived from the prepaid
mobile telephony services surcharge and local charge records of the Board;
NOW, THEREFORE IT IS RESOLVED AND ORDERED AS FOLLOWS:
Section 1. That the _______________________ or other officer or employee of the Local Jurisdiction (Title(s) of authorized position(s)) designated in writing by the _______________________ to the Board is hereby appointed to represent
(Title(s) of position(s) authorized to Designate) the Local Jurisdiction with authority to examine prepaid mobile telephony services surcharge and local
charge records of the Board pertaining to prepaid mobile telephony services surcharge and local
charges collected for the Local Jurisdiction by the Board pursuant to the contract between the Local
Jurisdiction and the Board. The information obtained by examination of Board records shall be used
only for purposes related to the collection of the Local Jurisdiction’s prepaid mobile telephony services
surcharge and local charges by the Board pursuant to the contract.
Section 2. That the _______________________ or other officer or employee of the Local Jurisdiction (Title(s) of authorized position(s)) designated in writing by the _______________________ to the Board is hereby appointed to represent (Title(s) of position(s) authorized to Designate) the Local Jurisdiction with authority to examine those prepaid mobile telephony services surcharge and
local charge records of the Board for purposes related to the following governmental functions of the
Local Jurisdiction:
a)_______________________________________________
b)_______________________________________________
c)_______________________________________________
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The information obtained by examination of Board records shall be used only for those governmental
functions of the Local Jurisdiction listed above.
Section 3. That ________________________________ is hereby designated to examine the prepaid (Firm or consultant) mobile telephony services surcharge and local charges records of the Board of Equalization pertaining
to prepaid mobile telephony services surcharge and local charges collected for the Local Jurisdiction by
the Board. The person or entity designated by this section meets all of the following conditions (Rev.
& Tax. Code, § 42110, subd. (b)(2)):
a)has an existing contract with the Local Jurisdiction that authorizes the person to examine the
prepaid mobile telephony services surcharge and local charge records;
b)is required by that contract with the Local Jurisdiction to disclose information contained in or
derived from, those records only to an officer or employee of the Local Jurisdiction authorized
by the resolution to examine the information;
c)is prohibited by that contract from performing consulting services for a seller during the term of
that contract;
d)is prohibited by that contract from retaining information contained in, or derived from, those
prepaid mobile telephony services surcharge and local charge records, after that contract has
expired.
The contract between the Local Jurisdiction and ________________________ designated by the Local
(Firm or consultant) Jurisdiction to request information from the Board shall be subject to the following limitations (Rev. &
Tax. Code, § 42103, subd. (g)):
a)____________________________ shall, to the same extent as the Board, be subject to Section(Firm or consultant) 55381, relating to unlawful disclosures.
b)the contract between the Local Jurisdiction and ______________________ shall not provide, in(Firm or consultant) whole or in part, in any manner a contingent fee arrangement as payment for services rendered.
BE IT FURTHER RESOLVED THAT the information obtained by examination of the Board
records shall only be used for purposes related to the collection of the Local Jurisdiction’s prepaid
mobile telephony services surcharge and local charges by the Board pursuant to the contract between
the Local Jurisdiction and Board, or for purposes related to other governmental functions of the Local
Jurisdiction, as identified above in section 2.
Introduced, approved and adopted this _______________ day of ________________________, 20___.
__________________________________________________________________________________
(Printed name & title) (Attest) __________________________________________________________________________________
(Signature) (Date)
resolutionmts Rev. 07/15
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Local Jurisdiction ______________
AGREEMENT FOR STATE COLLECTION AND ADMINISTRATION OF
LOCAL CHARGES
This Agreement is for the purpose of implementing the Local Prepaid Mobile Telephony
Services Collection Act (Part 21.1, commencing with Section 42100) of Division 2 of the
Revenue and Taxation Code), hereinafter referred to as the Local Charge Act. The
____________________________ and the State Board of Equalization, hereinafter called Insert name of local jurisdiction the Board, do agree as follows:
ARTICLE I
DEFINITIONS
Unless the context requires otherwise, wherever the following terms appear in this Agreement they shall be interpreted to mean the following:
A. “Administrative Expenses” means all expenses incurred by the Board in the
administration and collection of the local charges, including preparation and wind down costs which are reimbursable to the Board from the revenues collected by the Board on behalf of the local jurisdiction.
B. “Contingent Fee” includes, but is not limited to, a fee that is based on a
percentage of the tax liability reported on a return, a fee that is based on a percentage of the taxes owed, or a fee that depends on the specific tax result attained.
C. “Direct Seller” means a prepaid Mobile Telephony Service (MTS) provider or
service supplier, as defined in section 41007, that makes a sale of prepaid mobile
telephony services directly to a prepaid consumer for any purpose other than resale in the regular course of business. A direct seller includes, but is not limited to, a telephone corporation, a person that provides an interconnected Voice over Internet Protocol (VoIP)
service, and a retailer as described in section 42004(b)(1).
D. “Local Charges” means a utility user tax imposed on the consumption of prepaid mobile telephony services, as described in section 42102, and charges for access to communication services or to local “911” emergency telephone systems imposed by a
local jurisdiction, as described in section 42102.5.
E. “Local Jurisdiction” or “local agency” means a city, county, or city and county, which includes a charter city, county, or city and county of this State, which has adopted an ordinance imposing a local charge of the kind described in Part 21.1 of
Division 2 of the Revenue and Taxation Code and has entered into a contract with the
Board to perform all functions incident to the collection of the local charges.
F. “Ordinance” means an ordinance of a local jurisdiction imposing a local charge, including any local enactment relating to the filing of a refund or a claim arising
under the ordinance, attached hereto, as amended from time to time.
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G. “Quarterly local charges” means the total amount of local charges
transmitted by the Board to a local jurisdiction for a calendar quarter, as set forth in
section 42106(a)(1).
H. “Refund” means the amount of local charges deducted by the Board from a
local jurisdiction’s quarterly local charges in order to pay that jurisdiction’s share of a
local charge refund due to one taxpayer.
I. “Section” – all section references are to the Revenue and Taxation Code.
J. “Seller” means a person that sells prepaid mobile telephony service to a
person in a retail transaction.
ARTICLE II BOARD ADMINISTRATION AND COLLECTION OF LOCAL CHARGES
A. Administration. The Board and the local jurisdiction agree that the Board
shall perform functions incident to the collection of the local charges from sellers that are not direct sellers.
B. Collection. The Board shall collect the local charges in the same manner as it
collects the prepaid MTS Surcharge in the Prepaid Mobile Telephony Services Surcharge
Collection Act, subject to specified limitations in the Local Charge Act for which the local jurisdiction is responsible, as set forth in Article III of this Agreement.
C. Audits. The Board’s audit duties shall be limited to verification that the seller
that is not a direct seller complied with the Local Charge Act.
D. Other applicable laws. The Board and the local jurisdiction agree that all
provisions of law applicable to the administration and operation of the Local Charge Act,
Prepaid Mobile Telephony Services Surcharge Collection Act, and the Fee Collection
Procedures Law (FCPL) shall be applicable to the collection of local charges. References
in the FCPL to feepayer include a person required to pay the local charge, including the seller. All future amendments to applicable laws are automatically incorporated into this
Agreement.
E. Deposit of Local Charges. All local charges collected by the Board shall be
deposited in the Local Charges for Prepaid Mobile Telephony Services Fund in the State Treasury to be held in trust for the local taxing jurisdiction. Local charges shall consist
of all taxes, charges, interest, penalties, and other amounts collected and paid to the
Board, less payments for refunds and reimbursement to the Board for expenses incurred
in the administration and collection of the local charges, including preparation and wind-
down costs.
F. Allocation of Expenses. The Board shall allocate the total combined annual
expenses incurred for administration and collection pursuant to the Prepaid Mobile
Telephony Services Surcharge Collection Act and the Local Charge Act on a pro rata
basis according to revenues collected for: (1) the emergency telephone users surcharge portion of the prepaid MTS surcharge, (2) the Public Utilities Commission surcharges
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portion of the prepaid MTS surcharge, and (3) local charges. The Board shall charge a
local jurisdiction its pro rata share of the Board’s cost of collection and administration.
G. Transmittal of money. All local charges collected by the Board shall be transmitted to the local jurisdiction once in each calendar quarter. Transmittals may be
made by mail or by deposit to the account of the local jurisdiction in a bank designated
by that jurisdiction. The Board shall furnish a statement quarterly indicating the amounts
paid and withheld for expenses of the Board.
H. Rules. The Board shall prescribe and adopt such rules and regulations as in its
judgment are necessary or desirable for the administration and collection of local charges
and the distribution of the local charges collected.
I. Security. The Board agrees that any security which it hereafter requires to be furnished under the FCPL section 55022 will be upon such terms that it also will be
available for the payment of the claims of the local jurisdiction for local taxes owing to it
as its interest appears. The Board shall not be required to change the terms of any security
now held by it, and the local jurisdiction shall not participate in any security now held by
the Board.
J. Records of the Board.
1. Information obtained by the local jurisdiction from the examination of the
Board’s records shall be used by the local jurisdiction only for purposes related to the collection of the prepaid mobile telephony services surcharge and local charges by the
Board pursuant to this Agreement.
2. When requested by resolution of the legislative body of a local jurisdiction, the
Board shall permit any duly authorized officer or employee or other person designated by that resolution to examine any information for its own jurisdiction that is reasonably
available to the Board regarding the proper collection and remittance of a local charge of
the local jurisdiction by a seller, including a direct seller, subject to the confidentiality
requirements of sections 7284.6, 7284.7 and 19542. (sections 42110(b), 42103(e).).
3. The resolution of the local jurisdiction shall certify that any person designated by the resolution, other than an officer and an employee, meets all of the following
conditions:
a. Has an existing contract with the local jurisdiction that authorizes the person to examine the prepaid MTS surcharge and local charge records.
b. Is required by that contract with the local jurisdiction to disclose information
contained in or derived from, those records only to an officer or employee of
the local jurisdiction authorized by the resolution to examine the information. c. Is prohibited by that contract from performing consulting services for a seller
during the term of that contract.
d. Is prohibited by that contract from retaining information contained in, or derived from, those prepaid MTS surcharge and local charge records, after that contract has expired.
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4. Any third party contract between the local jurisdiction and an entity or person
authorized by the local jurisdiction to request information from the Board shall be subject
to the following limitations:
a. Any third party shall, to the same extent as the Board, be subject to Section
55381, relating to unlawful disclosures.
b. A third party contract shall not provide, in whole or in part, in any manner a contingent fee arrangement as payment for services rendered.
5. Information obtained by examination of Board records shall be used only for
purposes related to the collection of the prepaid MTS surcharge and local charges by the
board pursuant to the contract, or for purposes related to other governmental functions of the local jurisdiction set forth in the resolution.
6. If the Board believes that any information obtained from the Board’s records
related to the collection of the prepaid MTS surcharge and local charges has been
disclosed to any person not authorized or designated by the resolution of the local jurisdiction, or has been used for purposes not permitted by section 42110(b), the board
may impose conditions on access to its local charge records that the board considers
reasonable, in order to protect the confidentiality of those records. (section 42110 (c).)
7. The costs incurred by the Board in complying with a request for information shall be deducted by the Board from those revenues collected by the Board on behalf of
the local jurisdiction making the request, as authorized by section 42110(b)(1).
ARTICLE III LOCAL JURISDICTION ADMINISTRATION AND RESPONSIBILITIES
A. The local jurisdictions shall be solely responsible for all of the following:
1. Defending any claim regarding the validity of the ordinance in its application
to prepaid mobile telephony service. The claim shall be processed in accordance with the
provisions of the local ordinance that allows the claim to be filed.
2. Interpreting any provision of the ordinance, except to the extent specifically superseded by section 42105 of the Local Charge Act. The claim shall be processed in
accordance with the provisions of the local enactment that allows the claim to be filed.
3. Responding to specified consumer claims for refund involving: (1) rebutting
the presumed location of the retail transaction; (2) a consumer claim of exemption from the local charge under the ordinance; or (3) any action or claim challenging the validity
of a local tax ordinance, in whole or part. The claim shall be processed in accordance
with the provisions of the local enactment that allows the claim to be filed.
4. Refunding the taxes in the event a local jurisdiction or local government is ordered to refund the tax under the local ordinance.
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5. Reallocating local charges as a result of correcting errors relating to the
location of the point of sale of a seller or the known address of a consumer, for up to two
past quarters from the date of knowledge.
6. Collecting local charges on prepaid mobile telephony service and access to
communication services or access to local 911 emergency telephone systems imposed on
direct sellers.
7. Enforcement, including audits, of the collection and remittance of local charges by direct sellers pursuant to the ordinance.
8. The local jurisdiction shall be the sole necessary party defendant on whose
behalf the local charge is collected in any action seeking to enjoin collection of a local
charge by a seller, in any action seeking declaratory relief concerning a local charge, in any action seeking a refund of a local charge, or in any action seeking to otherwise
invalidate a local charge. There shall be no recovery from the State for the imposition of
any unconstitutional or otherwise invalid local charge that is collected under the Local
Act.
9. Entering into an agreement with the Board to perform the functions incident to
the collection of the local charges imposed on sellers that are not direct sellers.
10. Submitting an executed Certification to the Board, certifying that:
(a) the local jurisdiction’s ordinance applies the local charge to prepaid mobile telephony services;
(b) the amount of the rate charged for access to local 911 emergency telephone
systems or access to communications services complies with the requirements of section 42102.5; and/or applies the tiered rate for the utility user tax, as identified in section 42102.
(c) The local jurisdiction shall further certify that it agrees to indemnify and to
hold harmless the Board, its officers, agents, and employees for any and all liability for damages that may result from the Board’s collection pursuant to this Agreement.
11. Submitting signed documents to the Board to include agreement(s),
certification, copy of ordinance(s), and resolution(s).
12. Providing payment to the Board of the local jurisdiction’s pro rata share of the Board’s cost of collection and administration as established pursuant to subdivision (e) of
section 42020.
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ARTICLE IV LOCAL CHARGES
A. Local Charges – Timeliness – This part shall remain in effect until proposed California Code of Regulations, title 18, section 2460 is adopted by the Board and approved by the Office of Administrative Law.
1. Ordinances in effect as of September 1, 2015.
On or after January 1, 2016, a local charge imposed by a local jurisdiction on prepaid mobile telephony services shall be collected from the prepaid consumer by a seller at the
same time and in the same manner as the prepaid MTS surcharge is collected under Part
21 (commencing with section 42001) provided that, on or before September 1, 2015, the
local jurisdiction enters into a contract with the Board pursuant to section 42101.5.
Thereafter, all subsequently enacted local charges, increases to local charges, or other changes thereto, shall become operative pursuant to paragraphs (2), (3), and (4).
2. New charges. When a local jurisdiction adopts a new local charge after
September 1, 2015, the local jurisdiction shall enter into a contract with the Board,
pursuant to section 42101.5, on or before December 1st, with collection of the local charge to commence April 1st of the next calendar year.
3. Increases in local charges. When a local jurisdiction increases an existing
local charge after September 1, 2015, the local jurisdiction shall provide the Board
written notice of the increase, on or before December 1st, with collection of the local charge to commence April 1st of the next calendar year.
4. Inaccurate rate posted on the Board’s website. When a local jurisdiction
notifies the Board in writing that the rate posted on the Board’s Internet Web site (posted
rate) for a local charge imposed by that local jurisdiction is inaccurate, including scenarios where the local charge was reduced or eliminated, the recalculated rate
applicable to the local jurisdiction shall become operative on the first day of the calendar
quarter commencing more than 60 days from the date the Board receives the local
jurisdiction’s written notification that the posted rate is inaccurate.
A. Local Charges – Timeliness – This part shall take effect and supersede the above “Local Charges – Timeliness section when California Code of Regulations, title 18, section 2460 is adopted by the Board and approved by the
Office of Administrative Law.
1. Ordinances in effect as of September 1, 2015. On or after January 1, 2016,
a local charge imposed by a local jurisdiction on prepaid mobile telephony services shall
be collected from the prepaid consumer by a seller at the same time and in the same
manner as the prepaid MTS surcharge is collected under Part 21 (commencing with
section 42001) provided that, on or before September 1, 2015, the local jurisdiction enters into a contract with the Board pursuant to section 42101.5.
In the event a local jurisdiction does not enter into a contract with the Board by
September 1, 2015, the local jurisdiction may enter into a contract with the Board,
pursuant to section 42101.5, on or before December 1st, with collection of the local charge to commence April 1st of the next calendar year. Thereafter, all subsequently
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enacted local charges, increases to local charges, or other changes thereto, shall become
operative pursuant to paragraphs (2), (3), (4) and (5) of this subdivision.
2. New charges. When a local jurisdiction adopts a new local charge after September 1, 2015, the local jurisdiction shall enter into a contract with the Board,
pursuant to section 42101.5, on or before December 1st, with collection of the local
charge to commence April 1st of the next calendar year.
3. Increases in local charges. When a local jurisdiction increases an existing local charge after September 1, 2015, the local jurisdiction shall provide the Board
written notice of the increase, on or before December 1st, with collection of the local
charge to commence April 1st of the next calendar year.
4. Advance written notification. When a local charge is about to expire or decrease in rate, the local jurisdiction imposing the local charge shall notify the Board in
writing of the upcoming change, not less than 110 days prior to the date the local charge
is scheduled to expire or decrease. The change shall become operative on the first day of
the calendar quarter commencing after the specified date of expiration or decrease in rate.
If advance written notice is provided less than 110 days prior to the specified date of expiration or decrease in rate, the change shall become operative on the first day of the
calendar quarter commencing more than 60 days after the specified date of expiration or
decrease.
5. Inaccurate Rate Posted on the Board’s Web site. When a local jurisdiction notifies the Board in writing that the rate posted on the Board’s Internet Web site (posted
rate) for a local charge imposed by that local jurisdiction is inaccurate, including
scenarios where the local charge was reduced or eliminated and the local jurisdiction
failed to provide advance written notice pursuant to paragraph 4 of this subdivision, the recalculated rate applicable to the local jurisdiction shall become operative on the first day of the calendar quarter commencing more than 60 days from the date the Board
receives the local jurisdiction’s written notification that the posted rate is inaccurate. The
local jurisdiction shall promptly notify the Board in writing of any such discrepancies
with the posted rate that are known or discovered by the local jurisdiction. ARTICLE V
COMPENSATION The local jurisdiction agrees to pay the Board its pro rata share of the Board’s cost of
collection and administration of the local charges, as established pursuant to section
42020, subdivision (e). Such amounts shall be deducted from the local charges collected
by the Board for the local jurisdiction.
ARTICLE VI
MISCELLANEOUS PROVISIONS
A. Communications. Communications and notices may be sent by first-class United States Mail. A notification is complete when deposited in the mail.
Communications and notices to be sent to the Board shall be addressed to:
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State Board of Equalization
P.O. Box 942879 MIC: 27
Sacramento, California 94279-0001
Attention: Supervisor,
Local Revenue Allocation Unit
Communications and notices to be sent to the local jurisdiction shall be addressed to:
B. Term. The date of this Agreement is the date on which it is approved by the
Department of General Services. The Agreement shall take effect on the first day of the
calendar quarter next succeeding the date of such approval, but in no case before the
operative date of the local jurisdiction’s ordinance, nor on a day other than the first day of a calendar quarter. This Agreement shall be renewed automatically from year to year until January 1, 2020, when the Local Charge Act is repealed, unless a statute enacted
prior to that date extends that date. In such event, this Agreement will continue to renew
automatically from year to year to the date authorized by statute.
STATE BOARD OF EQUALIZATION
By_____________________________ Administrator, Return Analysis and Allocation Section
LOCAL JURISDICTION_________________
By_____________________________ (Signature on this line)
_______________________________
(Type name here)
_______________________________ (Type title here)
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1234 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/19/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Letter to President Obama expressing support for the Clean Power Plan and transitioningU.S. energy consumption to 100% renewable by 2050.
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Letter of Support
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:LettertoPresidentObamaexpressingsupportfortheCleanPowerPlanand
transitioning U.S. energy consumption to 100% renewable by 2050.
AuthorizetheMayortosignalettertoPresidentObamainsupportoftheCleanPowerPlanand
transitioning the nation’s energy consumption to be 100% renewable by 2050.
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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OFFICE OF THE CITY MANAGER
SUSTAINABILITY DIVISION
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-7603 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Letter to President Obama expressing support for the Clean Power Plan and
transitioning U.S. energy consumption to 100% renewable by 2050.
Recommended Action
Authorize the Mayor to sign a letter to President Obama in support of the Clean Power
Plan and transitioning the nation’s energy consumption to be 100% renewable by 2050.
Description
With the climate talks convening in Paris at the United Nations’ 21st Session of the
Conference of Parties (COP21) on December 4, a bipartisan group of local and state
elected officials across the country are writing a letter to support the nation's Clean
Power Plan with the goal of transitioning America to 100% clean energy by 2050. This
presents a rare and meaningful opportunity to show a commitment to climate
protection and so the Mayors Innovation Project is asking for cities to send letters of
support to President Obama on the Clean Power Plan. Other partners include the
Young Elected Officials Network, Local Progress, State Innovation Exchange, Advanced
Energy Economy, and the White House. The Mayors Innovation Project aiming for
elected officials from all 50 states and to sign on.
Sustainability Impact
The U.S. Clean Power Plan aligns with varied goals related to the implementation of the
City’s Climate Action Plan (CAP) and General Plan Environmental Resources/
Sustainability Element. The City of Cupertino is working to implement its Climate
Action Plan and reduce GHG emissions by 15% below 2010 levels by the year 2020.
Working to increase renewable energy is one of the most significant ways to reduce
GHG in the City’s energy sector. Through the implementation of Measure C-E-5, the
CAP envisions expansion of this capacity by 1.5MW in the residential and commercial
sectors by 2020 and 5.0MW by 2035. Also, through its partnership in the Silicon Valley
Clean Energy Partnership, Cupertino is leading an effort to explore Community Choice
Aggregation in Santa Clara County, allowing the community to procure its own sources
of clean renewable energy at competitive rates.
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Fiscal Impact
There are no direct financial impacts to writing a letter of support for the Clean Power
Plan.
_____________________________________
Prepared by: Misty Mersich, Sustainability Coordinator
Approved for Submission by: Erin Cooke, Assistant to the City Manager &
Sustainability Manager
Attachments:
A. Draft Support Letter
94
OFFICE OF THE MAYOR
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3200 www.cupertino.org
President Barak Obama
The White House
1600 Pennsylvania Avenue NW
Washington, DC 20500
December 1, 2015
Dear President Obama,
We, the undersigned local and state elected officials, strongly support the goal to
achieve more than 50 percent clean energy by 2030, putting us on the path to 100
percent clean energy sources by 2050. This is a necessary and achievable goal. With the
implementation of the Clean Power Plan, the EPA estimates that the United States will
increase our current generation of clean energy by 30 percent. This means we are
already on track to generate 43 percent clean energy by 2030 by effectively
implementing the Obama Administration’s policies. We appreciate the administration’s
leadership supporting clean energy—and with additional leadership at the federal,
state, and local levels, our country will successfully reach the 50 percent by 2030 goal.
Clean energy is an American success story. It is one of the fastest growing economic
sectors in the United States and already provides 360,000 jobs. The solar industry alone
employs 143,000 people—more individuals than work in coal mines—and grew 20
percent in 2014. Last year a new solar project was installed every 2.5 minutes.
Transitioning to clean energy isn’t just the smart choice for growing our economy—it
keeps our families healthy. According to the American Lung Association, almost half of
Americans live in places where pollution levels are too often dangerous to breathe. By
transitioning to clean energy, we can clear the air and reduce the health risks of
pollution. The time to act is now. Fourteen of the 15 warmest years on record have all
occurred since 2000, and 2014 was the warmest ever recorded. Our communities are
already feeling the growing costs of increased number of extreme weather events, such
as hurricanes, droughts, and flooding. According to NOAA, the frequency of billion-
dollar storm-related disasters has increased five percent each year since 1980. In Paris,
the United States and our global partners will offer concrete targets for reducing
greenhouse gas emissions to prevent the most devastating impacts of climate change.
However, true success in Paris—and in the days, weeks and months that follow—will
come down to America’s willingness to build on the momentum from the UN talks and
continue to lead the world by implementing clean energy solutions. States, cities and
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businesses are already paving the way with clean energy solutions that are substantially
and cost-effectively transitioning our country away from dirty fossil fuels and towards
clean sources like wind and solar. As leaders responsible for America’s present and
future prosperity, we must protect our communities from the dangers of climate
change. To ensure our economic prosperity, to protect our health and children, and to
ensure our security and safety, we need to act now to transition our country to more
than 50 percent clean energy by 2030.
Mayors Statement: The City of Cupertino is in the heart of Silicon Valley, and has been
an influential leader in advancing innovative approaches to mitigate climate change,
including active pursuits of energy independence, as detailed on our agency’s Climate
Action Plan (www.cupertino.org/green). Most recently our City has been leading the
effort to establish a partnership with four other local governments to bring Community
Choice Aggregation to Santa Clara County, through the Silicon Valley Community
Choice Energy Partnership (www.svcleanenergy.org). The Partnership is looking to
increase our local control of energy sources and increase our percentage of renewable
energy at a faster rate then what is currently being accomplished by Investor Owned
Utilities in the State, while maintaining competitive rates. With your continued
leadership at the federal level, clean energy can be a possibility for all Americans,
protecting our nation’s future generations from the impacts of climate change and
ensuring a more secure and cleaner future.
Very Respectfully,
Mayor Rod Sinks, City of Cupertino
96
CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1235 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/19/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Participate in the Compact of Mayors by sending a letter of commitment to the Compact ofMayors Secretariat.
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Letter of Intent
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:ParticipateintheCompactofMayorsbysendingaletterofcommitmenttothe
Compact of Mayors Secretariat.
AuthorizetheMayortosigntheletterofcommitmenttotheCompactofMayors,joining
coalitionsofmayorsandcityofficialsworldwidecommittingtoreducelocalgreenhousegas
emissions and enhance resilience to climate change.
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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OFFICE OF THE CITY MANAGER
SUSTAINABILITY DIVISION
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-7603 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Participate in the Compact of Mayors by sending a letter of commitment to the Compact
of Mayors Secretariat.
Recommended Action
Authorize the Mayor to sign the letter of commitment to the Compact of Mayors,
joining coalitions of mayors and city officials worldwide committing to reduce local
greenhouse gas emissions and enhance resilience to climate change.
Description
The Compact of Mayors is a global coalition of mayors and city officials committing to
reduce local greenhouse gas emissions, enhance resilience to climate change and track
their progress publicly. It is a voluntary agreement among cities to respond to climate
change in a consistent and complementary manner to national efforts. Like Cupertino,
many cities around the world are already acting to prepare and adapt to climate change
but their progress frequently goes unrecognized and is not measured or reported
consistently, so the Compact can help with this.
The Mayors Climate Compact was originally launched as the US Mayors Climate
Protection Agreement in 2005, which was an initiative to advance the goals of the Kyoto
Protocol through leadership and action by at least 141 American cities. The Kyoto
Protocol was an international treaty, which extends the 1992 United Nations
Framework Convention on Climate Change that commits State Parties to reduce
greenhouse gas emissions, based on the premise that global warming exists and man-
made CO2 emissions have caused it. Cupertino was among the list of cities that signed
this initial U.S. Mayors Climate Protection agreement in 2009 and has since been a
leader in pushing strong environmental sustainability goals and policy. Including,
conducting a 2005 baseline GHG inventory, 2010 GHG inventory update and adopting
the City’s Climate Action Plan (CAP) in January 2015.
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Since the initial agreement, climate science and universal knowledge about the threat
and impacts of climate change have evolved and are now seen as a major global threat.
The Compact of Mayors is a new international initiative started in 2014 which gives
cities the opportunity to be recognized as leaders in local climate change. The Compact
of Mayors was launched by a partnership of C40 Cities Climate Leadership Group
(C40), ICLEI – Local Governments for Sustainability (ICLEI) and the United Cities and
Local Governments (UCLG) –with support from UN-Habitat. The Compact establishes
a common platform to capture the impact of cities’ collective actions through
standardized measurement of emissions and climate risk, and consistent, public
reporting of their efforts.
This month, in Paris, the United Nations will hold its 21st annual Conference of the
Parties (COP 21), with the aim of achieving a universal agreement on climate among
nation states. The Compact represents the greatest opportunity to bring attention to and
quantify city action both in the lead-up to the Paris climate talks and beyond. The
Compact will collect significant climate action data that cities are already developing
and quantify the action that cities are taking collectively to reduce their contributions to
climate change while becoming more resilient to its effects.
The Compact requires the City to a specific course of action, many of which the City has
already completed:
1. Take inventory. Within one year, undertake an assessment of the current impacts
of climate change through a.) A city-wide inventory of greenhouse gas emissions
for buildings and transport sectors, b.) The identification of climate hazards, and
c.) a report on both
2. Create reduction targets and establish a system of measurement: Within two
years, the City must update its inventory to include a breakdown of emissions
for the waste sector; set a target to reduce its greenhouse gas emission; conduct a
climate change vulnerability assessment consistent with the Compact guidelines;
and report the results publicly.
3. Establish an action plan: Within three years, a city’s strategic plan must show
how it will deliver on its commitment to reduce greenhouse gas emissions and
adapt to climate change.
The City has already taken many actions over the years to address climate change and
therefore will be able to submit proof of completion of many these requirements along
with our initial application. One example is the City conducted greenhouse gas
inventories with 2005 and 2010 data, which includes a breakdown of emissions for
energy, transportation, water and waste sectors. Additionally, the Climate Action Plan
was adopted in January 2015, which outlines over 200 strategies the City will take to
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reduce GHG and includes a chapter on climate adaptation and hazards. City staff has
also been involved with the county-wide climate hazards and adaption effort, Silicon
Valley 2.0 through its technical advisory committee.
Sustainability Impact
Participation in the Compact of Mayors aligns with the goals related to the
implementation of the City’s CAP and General Plan Environmental Resources/
Sustainability Element. Through the CAP the City has set ambitious GHG targets, and
committed to continuing to monitoring progress and conducting regular GHG
inventory updates. Specifically, the CAP outlines the path to reduce greenhouse gases
by 95,661 MT CO2e by the year 2020 to meet our target of 15% below 2010 baseline year
by 2020 through the implementation of GHG measures.
Fiscal Impact
There is no direct financial impacts to joining the Compact of Mayors. Complying with
the compact requires tasks that the agency’s new Sustainability Coordinator will be
already doing as a part of the City’s Climate Action Plan implementation and
reporting.
_____________________________________
Prepared by: Misty Mersich, Sustainability Coordinator
Approved for Submission by: Erin M. Cooke, Assistant to the City Manager &
Sustainability Manager
Attachments:
A. Draft Compact of Mayors Letter of Intent
100
OFFICE OF THE MAYOR
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3200 www.cupertino.org
December 1, 2015
Dear Compact of Mayors Secretariat,
I hereby declare the intent of the City of Cupertino to comply with the Compact of Mayors,
the world’s largest cooperative effort among mayors and city leaders to reduce greenhouse
gas emissions, track progress, and prepare for the impacts of climate change worldwide.
The Compact of Mayors has defined a series of requirements that cities are expected to
meet over time, many of which Cupertino has already completed and we would be happy
to publically report and share our stage of development on the pathway to compliance with
the Compact.
I commit to advancing the City of Cupertino along the stages of the Compact, with the goal
of becoming fully compliant with all the requirements within three years. Specifically, I
pledge to publicly report. Our plan to address climate change mitigation and adaptation
within three years of less, which includes the following:
The greenhouse gas emissions inventory for our City was completed in 2010 using the
US Community Protocol which is consistent with the Global Protocol for Community-
Scale Greenhouse Gas Emission Inventory
Our Climate Action Plan, which was adopted in January 2015 and includes 225
Community-wide and Municipal measures
The climate hazards and vulnerabilities faced by our city, as outlined in the regional
project Silicon Valley 2.0
Our target to reduce greenhouse gas emissions 15% below 2010 baseline by the year
2020, 19% below 2010 baseline by 2035 and 83% below 2010 baseline by 2050
Sincerely,
Mayor Rod Sinks, City of Cupertino
101
CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1236 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/19/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Participation in the Institute for Local Government’s Beacon Award: Local Leadership towardSolving Climate Change Recognition Program
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Resolution
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Participation in the Institute for Local Government’s Beacon Award: Local
Leadership toward Solving Climate Change Recognition Program
AdoptResolution15-110supportingtheCity’sparticipationintheInstituteforLocal
Government’sBeaconAward:LocalLeadershiptowardSolvingClimateChangeRecognition
Program.
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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OFFICE OF THE CITY MANAGER
SUSTAINABILITY DIVISION
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-7603 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Participation in the Institute for Local Government’s Beacon Award: Local Leadership
toward Solving Climate Change Recognition Program
Recommended Action
Adopt Resolution 15-110 supporting the City’s participation in the Institute for Local
Government’s Beacon Award: Local Leadership toward Solving Climate Change
Recognition Program.
Description
The Beacon Award, an initiative of the Institute for Local Government (ILG), recognizes
and celebrates local governments that reduce greenhouse gas emissions (GHG) and
energy use; adopts policies and launches programs to address climate change; and
promotes community-wide sustainability. The ILG is a non-profit research and
education affiliate of the League of California Cities and the California State Association
of Counties. The Beacon Award is funded by California utility ratepayers and is
administered by multiple utilities including PG&E, under the auspices of the California
Public Utilities Commission.
In order to participate in the Beacon Award, the City must complete a simple
application and adopt a resolution to participate in the program; prepare or commit to
prepare a GHG inventory for city facilities and the community as a whole; prepare or
commit to prepare a climate action plan; and achieve measureable greenhouse gas
reductions and energy savings in agency facilities and community-wide. The City has
already taken actions over the years to address climate change and will be able to
submit proof of completion for many these requirements soon after applying for the
Award. Examples of the City’s Beacon Award-aligned efforts include; conducting
greenhouse gas inventories in the energy, transportation, water and waste sectors for
2005 and 2010. Additionally, the City’s Climate Action Plan (CAP), adopted in January
2015, outlines over 200 strategies Cupertino will take to reduce GHG and includes a
chapter on climate adaptation and hazards, a priority of the Beacon Award program.
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City staff has also been involved in regional climate change mitigation and adaptation
efforts including serving on the Joint Venture Silicon Valley Public Sector Climate Task
Force and the Technical Advisory Committee of Silicon Valley 2.0, the county-wide
climate hazards and adaption project.
Cupertino is well-positioned to participate in the Beacon Award to be recognized and
showcase its leadership in environmental sustainability. The Council has demonstrated
its commitment to climate action and sustainability through the adoption of the
Sustainability Element in the General Plan and the Climate Action Plan. To date,
Cupertino has many sustainability and climate related initiatives that deserve
recognition. These include but are not limited to, an award-winning Green Biz
program, successfully installing public electric vehicle charging stations; and current
efforts to explore Community Choice Energy through the Silicon Valley Community
Choice Energy Partnership. The City also recently expanded the Sustainability Division
to hire a Utility & Efficiency Analyst, tasked with municipal water and energy data
tracking and efficiency, and Sustainability Coordinator, tasked with implementing and
tracking emissions reductions and progress of the CAP, which will align with Beacon
Award requirements.
Participating cities and counties will be recognized with the Silver, Gold or Platinum
Beacon Award for achieving specific measurable GHG reductions, energy savings and
implementing best practices areas across ILG-defined categories such as Green Building
and Efficient Transportation, which align well with the City’s CAP sectors. The Silver
Beacon Award requires a demonstrated 5 percent reduction in agency and community
greenhouse gas emissions; the Gold Beacon Award requires a 10 percent reduction for
each; and the Platinum Beacon Award requires a 20 percent reduction. Participating
cities and counties must also demonstrate actions taken to save energy and implement
each of the ten best practice areas. There is no deadline or timeline for meeting award
level criteria; awards will be given out on an ongoing basis. Participants will be asked to
provide updates on their efforts to reduce greenhouse gas emissions and progress in
undertaking the best practice areas, GHG inventory, and climate action plan. ILG will
highlight participants’ accomplishments and offer appropriate and visible recognition
and tributes. Additional detailed information about the program can be found at
www.ca-ilg.org/BeaconAward.
Sustainability Impact
Participating in the Beacon Award program will increase the visibility of the City’s
climate leadership within our region and statewide. It is a great opportunity to
showcase our agency’s existing efforts to promote environmental leadership and
sustainability while working towards the award level targets. Cupertino has been a
leader with the adoption of the General Plan Environmental Resources/ Sustainability
Element and Climate Action Plan and this additional recognition at the State level will
be very valuable in helping to achieve our overall CAP goals and reduce GHG.
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Fiscal Impact
Program participation is voluntary. Participating in the program may help the City
increase competitiveness for future grant funding for implementation of the agency’s
Climate Action Plan. The Beacon Award is designed to supplement and piggyback on
existing efforts to reduce greenhouse gas emissions. Upon gaining Council support, the
Mayor will sign and send the letter to be considered as a Beacon Award participant to
participate. Staff will work towards achieving the award levels at our own pace. There
is no deadline or timeline for meeting award level criteria; awards will be given out on
an ongoing basis. However, participants are asked to provide periodic information
about efforts to reduce greenhouse gas emissions and save energy and as well as
progress in completing a greenhouse gas inventory, climate action plan and
undertaking activities in the ten best practice areas. These are all efforts that staff is
already doing to implement, track and report on our own Climate Action Plan, so
minimal additional staff time will be needed.
_____________________________________
Prepared by: Misty Mersich, Sustainability Coordinator
Approved for Submission by: Erin Cooke, Assistant to the City Manager &
Sustainability Manager
Attachments:
A. Draft Beacon Award Resolution
B. Beacon Award Information Brochure
105
RESOLUTION NO. 15-110
A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF CUPERTINO TO
PARTICIPATE IN THE INSTITUTE FOR LOCAL GOVERNMENT’S BEACON
AWARD: LOCAL LEADERSHIP TOWARD SOLVING CLIMATE CHANGE
WHEREAS, the City of Cupertino is undertaking policies, programs and
activities to reduce greenhouse gas emissions and save energy; and
WHEREAS, these policies, programs and activities conserve natural resources,
save energy and money, and promote sustainable land use and transportation planning
in the community; and
WHEREAS, cities and counties statewide are leading by example by adopting
innovative sustainability programs and policies, including working with community
residents, business groups and others; and
WHEREAS, Cupertino continues to be a regional climate leader, offering award-
winning, grant-funded, publically-recognized programs, policies and services that are
sought after and modeled by adjacent communities; and
WHEREAS, the City's Climate Action Plan, General Plan Sustainability Element,
Green Purchasing Policy, Green Events Policy, Green Building Ordinance, Green
Business Program, among others, have enabled our agency's advancement as a
sustainability practitioner that gets results in the form of greenhouse gas emissions
reductions, cost savings and community health & wellness benefits; and
WHEREAS, Cupertino wishes to expand these activities, share its experiences
with other communities, and be recognized for its accomplishments; and
WHEREAS, the Beacon Award: Local Leadership Toward Solving Climate
Change is a voluntary program of the Institute for Local Government, the non-profit
research and education affiliate of the California State Association of Counties and the
League of California Cities; and
WHEREAS, the Beacon Award recognizes and celebrates achievements of cities
and counties that reduce greenhouse gas emissions and save energy; and
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WHEREAS, participating in the Beacon Award is an opportunity for Cupertino
to be recognized for its efforts to promote sustainability, reduce greenhouse gas
emissions and save energy; now, therefore be it
NOW, THEREFORE, BE IT RESOLVED, that Cupertino City Council agrees to
participate in the Beacon Award: Local Leadership Toward Solving Climate Change;
BE IT FURTHER RESOLVED that the City of Cupertino will work towards achieving
the Silver, Gold and/or Platinum Beacon Award levels.
Vote Members of the City Council
AYES:
NOES:
ABSENT:
ABSTAIN:
ATTEST: APPROVED:
_______________________ ________________________________
Grace Schmidt, City Clerk Rod Sinks, Mayor, City of Cupertino
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1205 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/3/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Declare weeds a nuisance and set hearing date of January 19 for objections to proposedremoval
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Draft Resolution
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:DeclareweedsanuisanceandsethearingdateofJanuary19forobjectionsto
proposed removal
AdoptResolutionNo.15-112declaringweedsanuisanceandsettinghearingdateofJanuary
19 for objections to proposed removal
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
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OFFICE OF THE CITY CLERK
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3223 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Declare weeds a nuisance and set hearing date of January 19 for objections to proposed
removal.
Recommended Action
Adopt the Draft Resolution declaring weeds a nuisance and setting a hearing date of
January 19 for objections to proposed removal.
Discussion
Chapter 9.08 of the Cupertino Municipal Code requires property owners to remove or
destroy weeds on their property for fire protection. The weed abatement process is in
place to notify the property owners of this responsibility, authorize the County to
remove the weeds if the property owner doesn’t, and allow the County to recover the
costs of abatement.
*Please note that any fees waived by the Council will be billed to the City by the County
to cover their cost of servicing the property.
The process consists of eight steps that begin in November and go through August of
each year. At this time the process is at Step No. 2 on the list.
1. County prepares a list of all properties that have been non-compliant in
removing weeds in the last three years and provides that list to the City (Nov).
2. City Council adopts a resolution declaring weeds a nuisance and setting a
hearing date to hear objections by property owners to having their name on the
list (Dec).
3. County sends notice to the property owners on the list notifying them of the
hearing date and explaining that they must remove weeds by the abatement
deadline of April 30 or it will be done for them, and the cost of the abatement
plus administrative costs assessed to their property (Dec).
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4. City Council holds the hearing to consider objections by property owners and
adopts a resolution ordering abatement (Jan).
5. County sends a courtesy letter to property owners on the list notifying them
again of the abatement deadline and noting that they will work with the
property owner to be sure the weeds are removed (Jan).
6. After April 30, the properties are inspected by the County to verify that weeds
were removed and proceeds with abatement if the inspection fails. County
makes an assessment list of all costs associated with the abatement and provides
that list to the City (June-July).
7. City notifies the property owners on the assessment list notifying them of the
hearing date. (July-Aug).
8. City Council holds a hearing, notes any disputes, and adopts a resolution putting
a lien assessment on the properties to allow the County to recover the cost of
weed abatement (July-Aug).
_____________________________________
Prepared by: Kirsten Squarcia, Deputy City Clerk
Reviewed by: Grace Schmidt, City Clerk
Approved for Submission by: David Brandt, City Manager
Attachments: A - Draft Resolution
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RESOLUTION NO. 15-
A RESOLUTION OF THE CUPERTINO CITY COUNCIL
DECLARING WEEDS ON CERTAIN DESCRIBED PROPERTY TO BE A
PUBLIC NUISANCE AND SETTING A HEARING FOR OBJECTIONS TO
PROPOSED REMOVAL
WHEREAS, weeds are growing in the City of Cupertino upon certain
streets, sidewalks, highways, roads and private property; and
WHEREAS, said weeds may attain such growth as to become a fire
menace or which are otherwise noxious or dangerous; and
WHEREAS, said weeds constitute a public nuisance;
NOW, THEREFORE, BE IT RESOLVED by the City Council of the City of
Cupertino as follows:
1. That said weeds do now constitute a public nuisance;
2. That said nuisance exists upon all of the streets, sidewalks, highways,
roads and private property more particularly described by common
names or by reference to the tract, block, lot, code area, and parcel number
on the report prepared by the Agricultural Commissioner and attached
hereto;
3. That the 19th day of January, 2016, at the hour of 6:45 p.m., or as soon
thereafter as the matter can be heard, in the Council Chamber in the
Community Hall, City of Cupertino, is hereby set as the time and place
where all property owners having any objections to the proposed removal
of such weeds may be heard;
4. That the Agricultural Commissioner is hereby designated and ordered as
the person to cause notice of the adoption of this resolution to be given in
the manner and form provided in Sections 9.08.040 of the Cupertino
Municipal Code.
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Resolution No. 15-
Page 2
PASSED AND ADOPTED at a regular meeting of the City Council of the City of
Cupertino this 1st day of December, 2015, by the following vote:
Vote Members of the City Council
AYES:
NOES:
ABSENT:
ABSTAIN:
ATTEST: APPROVED:
______________________ ________________________________
Grace Schmidt, City Clerk Rod Sinks, Mayor, City of Cupertino
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1199 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:10/27/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Blackberry Farm Golf Course Maintenance Agreement, Contract Award
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Draft Contract
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Blackberry Farm Golf Course Maintenance Agreement, Contract Award
AuthorizetheCityManagertoaward,negotiateandexecuteacontractwithProfessionalTurf
ManagementofSanJose,Californiaintheamountof$99,600,asselectedthroughaRequest
forQualificationprocess,andfurtherauthorizetheCityManagertoexecuteannualextensions
tothecontractforuptofiveyearsbaseduponthepricinginthebiddocuments,subjectto
appropriation
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™113
1
DEPARTMENT OF RECREATION & COMMUNITY SERVICES
CITY HALL
10 10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3354 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Blackberry Farm Golf Course Maintenance, Contract Award
Recommended Action
Authorize the City Manager to award, negotiate and execute a contract with
Professional Turf Management of San Jose, California in the amount of $99,600, as
selected through a Request for Qualification process, and further authorize the City
Manager to execute annual extensions to the contract for up to five years based upon
the pricing in the bid documents, subject to appropriation.
Background
Maintenance of Blackberry Farm Golf Course has been contracted since spring 2002.
The current maintenance contract was bid and awarded in 2010. It had a two-year
initial term, with the option for annual renewals for three more years through June
2015. The term was extended by the City Council on June 17, 2015 for an additional six
months to December 31, 2015.
Bid Process
Bid documents for maintenance of Blackberry Farm Golf Course were prepared and
issued. Notices were mailed to local plan rooms and builders exchanges, and bid
documents posted on the City’s website. The project was advertised on November 7,
2015 in a newspaper with regional circulation (San Jose Mercury News). A pre-bid
conference was held on November 13.
On November 23, 2015, the City opened bids. One company submitted bids for this
project. The following is a summary of bids, for an initial 6 months of maintenance:
Bidder Bid Amount
Professional Turf Management $ 99,600
The Bid Form addresses a base bid for the first 6 months of maintenance, from January
to June 2016. Thereafter two more optional years of maintenance are priced on an
annual basis, and structured to align with the city’s fiscal year and the annual
appropriation cycle. The price bid for these two years is $205,200. Thereafter up to
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three further years of maintenance could be added annually, with the fee escalated
based upon the San Francisco/Oakland Consumer Price Index (CPI).
Maintenance of the golf course was most recently bid in 2010. At that time, two firms
submitted bids and associated qualifications information. One firm was found to be
non-responsive and the proposal rejected. The second firm, Professional Turf
Management, was deemed responsive and responsible, and was awarded a contract.
This firm has provided continuous maintenance services at Blackberry Farm Golf
Course. They have performed well at our course, especially given the condition of the
golf course infrastructure and the proximity of Stevens Creek and sensitive wildlife.
Discussion
The request for qualification bid process was conducted in a manner consistent with
applicable criteria of city ordinance, municipal code and public contracts code. This
RFQ process is more appropriate than simply awarding to the lowest bidder for the
following reasons:
The irrigation system at BBF Golf Course is over 50 years old and much of it is
original. It uses hydraulic valves; such valves and associated parts are no longer
available. Manual operation of the valves and controls is also required.
Maintaining such antiquated equipment involves specialized knowledge.
There are no ‘as-built’ or record drawings of the infrastructure. The irrigation
system does not provide coverage of the turf; extensive hand-watering is needed.
Some areas require hand watering year round and additional areas need
seasonal hand watering. The system is prone to frequent but unpredictable
failures which require immediate repair. These conditions are outside the normal
range or experience for golf maintenance.
BBF Golf Course is located along Stevens Creek. It is in the creek’s floodplain
and drains to the creek. The creek corridor contains a variety of protected
wildlife species. Presence of these species affects how the course may be
maintained. Various maintenance actions that are routine in typical settings are
inappropriate or prohibited in our setting. In particular, Stevens Creek hosts a
year-round population of federally-threatened steelhead and is a known rearing
zone for young steelhead. Certain maintenance actions can immediately
adversely affect such species. The potential consequences of a poor choice by an
ignorant or inexperienced maintenance firm could be dire for wildlife.
The Statement of Qualifications for bidders requested information regarding the firms’
experience with old irrigation equipment similar to ours, similarly undocumented and
antiquated infrastructure necessitating manual operations, and a similar wildlife
setting. Based upon the bid documents received, the firm of Professional Turf
Management has the appropriate experience and knowledge to provide the needed
maintenance services at the golf course, in a manner that will be safe and successful.
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Professional Turf Management’s qualifications were reviewed and found to be
appropriate for the unique conditions at the Blackberry Farm Golf Course setting.
The bid cost is deemed reasonable. The current cost to maintain the golf course is
$187,280 per year, equaling $93,640 per 6 months. This amount is based upon bids
received in 2010, with an adjustment the last 3 years based upon the San
Francisco/Oakland CPI. Staff believes that the effort to keep the golf course properly
maintained is now higher than was benchmarked in 2010. Higher effort and associated
higher costs are due to continued decline in the course’s infrastructure because of its
age, and extensive subsequent failures of the irrigation system necessitating increasing
hand watering and manual operations, all of which increase the cost to perform
maintenance.
Staff recommends that Council find that the RFQ process, rather than lowest bid, is
appropriate due to the unique nature of this contract, and authorize the City Manager
to award, negotiate and execute the contract to Professional Turf Management as
described above; and, further, authorize the City Manager to provide annual extensions
to the contract for up to five years based upon the pricing in the bid documents, and
subject to appropriation.
Fiscal Impact
Sufficient funds have been budgeted in FY 2015/16 for the proposed 6-month initial
term. No additional funds are required.
_____________________________________
Prepared by: Gail Seeds, Park Improvement Manager
Reviewed by: Carol Atwood, Director of Recreation & Community Services
Approved for Submission by: David Brandt, City Manager
Attachments:
A - Draft Contract
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Contractor Agreement
Blackberry Farm Golf Course Maintenance 2016
EXHIBIT A
DRAFT CONTRACT
AGREEMENT BETWEEN THE CITY OF CUPERTINO AND______________
FOR BLACKBERRY FARM GOLF COURSE MAINTENANCE
THIS AGREEMENT, for reference dated___________, 2015, is by and between CITY OF
CUPERTINO, a municipal corporation (hereinafter referred to as "City"), and , a (California
corporation, partnership, sole proprietor, individual) whose address is hereinafter called the
Contractor, and is made with reference to the following:
RECITALS:
A. City is a municipal corporation duly organized and validly existing under the laws
of the State of California with the power to carry on its business as it is now being conducted under
the Constitution and the statutes of the State of California and the Cupertino Municipal Code.
B. City and Contractor desire to enter into an agreement for Blackberry Farm Golf
Course Maintenance, in accordance with the Technical Provisions, General and Special Conditions,
and Special Environmental Conditions.
NOW, THEREFORE, it is mutually agreed by and between the undersigned parties as
follows:
1. TERM:
The Contractor shall begin work on January 1, 2016 and continue work through June 30,
2016, and shall diligently prosecute the work. This Agreement may be renewed annually for one-
year terms commencing July 1, 2016 through June 30, 2017, at the City’s sole discretion and subject
to appropriation, for up to five (5) one-year terms (possible total term 5.5 years).
2. SERVICES TO BE PERFORMED:
Contractor agrees, at its own cost and expense, to furnish all labor, tools, equipment,
materials, except as otherwise specified, and to do all work strictly in accordance with the Scope of
Work (see Exhibit A), The General and Special Conditions, Technical Provisions and Special
Environmental Conditions are hereby referred to and expressly made a part hereof with the same
force and effect as if the same were fully incorporated herein.
3. COMPENSATION TO CONTRACTOR:
Contractor shall be compensated for services performed pursuant to this Agreement in the
amount and manner set forth in Contractor's bid, which is attached hereto as Exhibit "A" and
incorporated herein by this reference. Payment will be made in the same manner that claims of a
like character are paid by the City, with checks drawn on the treasury of the City, to be taken from
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the fund as indicated in the city’s adopted budget.
4. TIME IS OF THE ESSENCE:
Contractor and City agree that time is of the essence regarding the performance of this
Agreement.
5. STANDARD OF CARE:
Contractor agrees to perform all services hereunder in a manner commensurate with the
prevailing standards of like professionals in the San Francisco Bay Area and agrees that all services
shall be performed by qualified and experienced personnel who are not employed by the City nor
have any contractual relationship with City.
6. INDEPENDENT PARTIES:
City and Contractor intend that the relationship between them created by this Agreement is
that of an independent contractor. The manner and means of conducting the work are under the
control of Contractor, except to the extent they are limited by statute, rule or regulation and the
express terms of this Agreement. No civil service status or other right of employment will be
acquired by virtue of Contractor's services. None of the benefits provided by City to its employees,
including but not limited to unemployment insurance, workers' compensation plans, vacation and
sick leave are available from City to Contractor, its employees or agents. Deductions shall not be
made for any state or federal taxes, FICA payments, PERS payments, or other purposes normally
associated with an employer-employee relationship from any fees due Contractor. Payments of the
above items, if required, are the responsibility of Contractor.
7. IMMIGRATION REFORM AND CONTROL ACT (IRCA):
Contractor assumes any and all responsibility for verifying the identity and employment
authorization of all of its employees performing work hereunder, pursuant to all applicable IRCA
or other federal, or state rules and regulations. Contractor shall indemnify and hold City harmless
from and against any loss, damage, liability, costs or expenses arising from any noncompliance of
this provision by Contractor.
8. NON-DISCRIMINATION:
Consistent with City's policy that harassment and discrimination are unacceptable
employer/employee conduct, Contractor agrees that harassment or discrimination directed toward
a job applicant, a City employee, or a citizen by Contractor or Contractor's employee on the basis of
race, religious creed, color, national origin, ancestry, handicap, disability, marital status, pregnancy,
sex, age, or sexual orientation will not be tolerated. Contractor agrees that any and all violations of
this provision shall constitute a material breach of this Agreement.
9. HOLD HARMLESS:
Contractor shall, to the fullest extent allowed by law, indemnify, defend, and hold harmless
the City and its officers, officials, agents, employees and volunteers against any and all liability,
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claims, stop notices, actions, causes of action or demands whatsoever from and against any of them,
including any injury to or death of any person or damage to property or other liability of any
nature, arising out of, pertaining to, or related to the performance of this Agreement by Contractor
or Contractor’s employees, officers, officials, agents or independent contractors. Contractor shall
not be obligated under this Agreement to indemnify City to the extent that the damage is caused by
the sole or active negligence or willful misconduct of City, its agents or employees. Such costs and
expenses shall include reasonable attorneys’ fees of counsel of City’s choice, expert fees and all
other costs and fees of litigation.
Contractor agrees to obtain executed indemnity agreements with provisions identical to
those set forth here in these sections from each and every subcontractor or any other person or
entity involved by, for, with, or on behalf of Contractor in the performance of this agreement. If
Contractor fails to obtain such indemnity obligations from others as required here, Contractor
agrees to be fully responsible according to the terms of this section.
10. INSURANCE:
On or before the commencement of the terms of this Agreement, Contractor shall furnish
City with certificates showing the type, amount, class of operations covered, effective dates and
dates of expiration of insurance coverage in compliance with paragraph 10A, B, C and D. Such
certificates, which do not limit Contractor's indemnification, shall also contain substantially the
following statement: "Should any of the above insurance covered by this certificate be canceled or
coverage reduced before the expiration date thereof, the insurer affording coverage shall provide
thirty (30) days' advance written notice to the City of Cupertino by certified mail, "Attention: City
Manager." It is agreed that Contractor shall maintain in force at all times during the performance of
this Agreement all appropriate coverage of insurance required by this Agreement with an
insurance company that is acceptable to City and licensed to do insurance business in the State of
California. Endorsements naming the City as additional insured shall be submitted with the
insurance certificates. Contractor to complete the attached Document 00530 Insurance Forms.
A. COVERAGE:
Contractor shall maintain the following insurance coverage:
(1) Workers' Compensation:
Statutory coverage as required by the State of California; Employers’ Liability
$1,000,000 per occurrence
(2) General Liability:
Commercial general liability coverage in the following minimum limits:
Bodily Injury: $500,000
each occurrence
$1,000,000
aggregate - all other
Property Damage: $500,000 each occurrence
$1,000,000 aggregate
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If submitted, combined single limit of $1,000,000 per occurrence; $2,000,000 in
the aggregate will be considered equivalent to the required minimum limits
shown above.
(3) Automotive:
Comprehensive automobile liability coverage in the
following minimum limits:
Bodily injury: $500,000 each occurrence
Property Damage: $500,000 each occurrence
or
Combined Single Limit: $1,000,000 each occurrence
B. SUBROGATION WAIVER:
Contractor agrees that in the event of loss due to any of the perils for which it has agreed to
provide comprehensive general and automotive liability insurance, Contractor shall look solely to
its insurance for recovery. Contractor hereby grants to City, on behalf of any insurer providing
comprehensive general and automotive liability insurance to either Contractor or City with respect
to the services of Contractor herein, a waiver of any right to subrogation which any such insurer of
said Contractor may acquire against City by virtue of the payment of any loss under such
insurance.
C. FAILURE TO SECURE:
If Contractor at any time during the term hereof should fail to secure or maintain the
foregoing insurance, City shall be permitted to obtain such insurance in the Contractor's name or as
an agent of the Contractor and shall be compensated by the Contractor for the costs of the insurance
premiums at the maximum rate permitted by law and computed from the date written notice is
received that the premiums have not been paid.
D. ADDITIONAL INSURED:
City, its City Council, boards and commissions, officers, employees, and volunteers shall be
named as an additional insured under all insurance coverages, except worker’s compensation
insurance. The naming of an additional insured shall not affect any recovery to which such
additional insured would be entitled under this policy if not named as such additional insured. An
additional insured named herein shall not be held liable for any premium, deductible portion of
any loss, or expense of any nature on this policy or any extension thereof. Any other insurance held
by an additional insured shall not be required to contribute anything toward any loss or expense
covered by the insurance provided by this policy.
E. SUFFICIENCY OF INSURANCE:
The insurance limits required by City are not represented as being sufficient to protect
Contractor. Contractor is advised to consult Contractor's insurance broker to determine adequate
coverage for Contractor.
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11. BONDS:
Not applicable.
12. PROHIBITION AGAINST TRANSFERS:
Contractor shall not assign, sublease, hypothecate, or transfer this Agreement, or any
interest therein, directly or indirectly, by operation of law or otherwise, without prior written
consent of City. Any attempt to do so without said consent shall be null and void, and any
assignee, sublessee, hypothecate or transferee shall acquire no right or interest by reason of such
attempted assignment, hypothecation or transfer. However, claims for money by Contractor from
City under this Agreement may be assigned to a bank, trust company or other financial institution
without prior written consent. Written notice of such assignment shall be promptly furnished to
City by Contractor.
The sale, assignment, transfer or other disposition of any of the issued and outstanding
capital stock of Contractor, or of the interest of any general partner or joint venturer or syndicate
member or cotenant, if Contractor is a partnership or joint venture or syndicate or cotenancy, which
shall result in changing the control of Contractor, shall be construed as an assignment of this
Agreement. Control means fifty percent (50%) or more of the voting power of the corporation.
13. SUBCONTRACTOR APPROVAL:
Unless prior written consent from City is obtained, only those people and subcontractors
whose names are listed in Contractor's bid shall be used in the performance of this Agreement.
Requests for additional subcontracting shall be submitted in writing, describing the scope of
work to be subcontracted and the name of the proposed subcontractor. Such request shall set forth
the total price or hourly rates used in preparing estimated costs for the subcontractor's services.
Approval of the subcontractor may, at the option of City, be issued in the form of a Work Order.
In the event that Contractor employs subcontractors, such subcontractors shall be required
to furnish proof of workers' compensation insurance and shall also be required to carry general and
automobile liability insurance in reasonable conformity to the insurance carried by Contractor. In
addition, any work or services subcontracted hereunder shall be subject to each provision of this
Agreement.
14. PERMITS AND LICENSES:
Contractor, at its sole expense, shall obtain and maintain during the term of this Agreement,
all appropriate permits, certificates and licenses, including a City Business License, that may be
required in connection with the performance of services hereunder.
15. REPORTS:
Each and every report, draft, work product, map, record and other document reproduced,
prepared or caused to be prepared by Contractor pursuant to or in connection with this Agreement
shall be the exclusive property of City. Consultant may retain a copy of any report furnished to the
City pursuant to this Agreement.
No report, information nor other data given to or prepared or assembled by Contractor
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pursuant to this Agreement shall be made available to any individual or organization by Contractor
without prior approval by City.
Contractor shall, at such time and in such form as City may require, furnish reports
concerning the status of services required under this Agreement.
16. RECORDS:
Contractor shall maintain complete and accurate records with respect to sales, costs,
expenses, receipts and other such information required by City that relate to the performance of
services under this Agreement.
Contractor shall maintain adequate records of services provided in sufficient detail to
permit an evaluation of services. All such records shall be maintained in accordance with generally
accepted accounting principles and shall be clearly identified and readily accessible. Contractor
shall provide free access to such books and records to the representatives of City or its designees at
all proper times, and gives City the right to examine and audit same, and to make transcripts
therefrom as necessary, and to allow inspection of all work, data, documents, proceedings and
activities related to this Agreement. Such records, together with supporting documents, shall be
kept separate from other documents and records and shall be maintained for a period of three (3)
years after receipt of final payment.
If supplemental examination or audit of the records is necessary due to concerns raised by
City's preliminary examination or audit of records, and the City's supplemental examination or
audit of the records discloses a failure to adhere to appropriate internal financial controls, or other
breach of contract or failure to act in good faith, then Contractor shall reimburse City for all
reasonable costs and expenses associated with the supplemental examination or audit.
17. NOTICES:
All notices, demands, requests or approvals to be given under this Agreement shall be given
in writing and conclusively shall be deemed served when delivered personally or on the second
business day after the deposit thereof in the United States Mail, postage prepaid, registered or
certified, addressed as hereinafter provided.
All notices, demands, requests, or approvals from Contractor to City shall be addressed to
City at:
City of Cupertino
10300 Torre Avenue
Cupertino CA 95014
Attention: Carol Atwood, Director of Recreation and Community Services
All notices, demands, requests, or approvals from City to Contractor shall be addressed to
Contractor at:
____________________________
____________________________
____________________________
____________________________
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18. URBAN RUNOFF MANAGEMENT:
The Contractor shall avoid creating excess dust when breaking asphalt or concrete and
during excavation and grading or other activities that may create dust or erosion. If water is used
for dust control, contractor shall use as little as necessary. Contractor shall take all steps necessary
to keep wash water out of the streets, gutters and storm drains.
The Contractor shall develop and implement erosion and sediment control to prevent
pollution of storm drains. Such control includes but is not limited to:
A. Use storm drain inlet protection devices such as sand bag barriers, filter fabric
fences, block and gravel filters. (Block storm drain inlets prior to the start of the rainy season
(October 15), in site de-watering activities and saw-cutting activities; shovel or vacuum saw-cut
slurry and remove from the site).
B. Cover exposed piles of soil or construction material with plastic sheeting. All
construction materials must be stored in containers.
C. Sweep and remove all materials from paved surfaces that drain to streets, gutters
and storm drains prior to rain as well as at the end of the each work day. At the completion of the
project, the street shall be washed and the wash water shall be collected and disposed of offsite in
an appropriate location.
D. After breaking old pavement, Contractor shall remove all debris to avoid contact
with rainfall or runoff.
E. Contractor shall maintain a clean work area by removing trash, litter, and debris at
the end of each work day. Contractor shall also clean up any leaks, drips, and other spills as they
occur.
The objective is to ensure that the City and County of Santa Clara County-Wide Clean
Water Program is adequately enforced. These controls should be implemented prior to the start of
construction, up-graded as required, maintained during construction phases to provide adequate
protection, and removed at the end of construction.
These recommendations are intended to be used in conjunction with the State’s Best
Management Practices Municipal and Construction Handbooks, local program guidance materials
from municipalities, Section 7.1.01 of the Standard Specifications and any other appropriate
documents on storm water quality controls for construction.
Failure to comply with this program will result in the issuance of noncompliance notices,
citations, project stop orders or fines. The fine for noncompliance of the above program is two
hundred and fifty dollars ($250.00) per occurrence per day. The State under the Federal Clean
Water Act can also impose a fine on the contractor, pursuant to Cal. Water Code '13385.
19. TERMINATION:
In the event Contractor fails or refuses to perform any of the provisions hereof at the time
and in the manner required hereunder, Contractor shall be deemed in default in the performance of
this Agreement. If such default is not cured within a period of two (2) days after receipt by
Contractor from City of written notice of default, specifying the nature of such default and the steps
necessary to cure such default, City may terminate the Agreement forthwith by giving to the
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Contractor written notice thereof.
City shall have the option, at its sole discretion and without cause, of terminating this
Agreement by giving seven (7) days' prior written notice to Contractor as provided herein. Upon
termination of this Agreement, each party shall pay to the other party that portion of compensation
specified in this Agreement that is earned and unpaid prior to the effective date of termination.
20. COMPLIANCES:
Contractor shall comply with all state or federal laws and all ordinances, rules and
regulations enacted or issued by City. Specifically, and without limitation, Contractor shall comply
with all state, federal, or local regulation regarding the removal and disposal of hazardous waste.
A. PREVAILING WAGES: To the extent applicable,Contractor shall comply with the
City’s Labor Compliance Program and all other requirements set forth in Labor Code section 1770
et seq. Contractor shall pay prevailing wages. Contractor will submit monthly certified payroll
records to the City for all employees and subcontractors in a preapproved format or a City
provided form. Any delay in remitting certified payroll reports to the City upon request from the
City will result in either delay and/or forfeit of outstanding payment to Contractor.
B. WORKING DAY: Contractor shall comply with California Labor Code Section
1810, et seq. which provides that work performed by employees of contractors in excess of 8 hours
per day, and 40 hours during any one week, must be compensated as overtime, at not less than 1 ½
times the basic rate of pay, to the extent applicable.
C. PAYROLL RECORDS: Contractor shall comply with California Labor Code Section
1776 which requires certified payroll records be maintained with the name, address, social security
number, work classification, straight time and overtime hours worked each day and week, and the
actual per diem wages paid to each journeyman, apprentice, worker, or other employee employed
by him or her in connection with this Agreement, to the extent applicable. The Payroll Records
shall be made available for inspection as provided in California Labor Code Section 1776.
D. APPRENTICES: Contractor shall comply with California Labor Code Section 1777.5
regarding apprentices, to the extent applicable.
21. CONFLICT OF LAW:
This Agreement shall be interpreted under, and enforced by the laws of the State of
California excepting any choice of law rules which may direct the application of laws of another
jurisdiction. The Agreement and obligations of the parties are subject to all valid laws, orders,
rules, and regulations of the authorities having jurisdiction over this Agreement (or the successors
of those authorities.) Any suits brought pursuant to this Agreement shall be filed with the courts
of the County of Santa Clara, State of California.
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22. ADVERTISEMENT:
Contractor shall not post, exhibit, display or allow to be posted, exhibited, displayed any
signs, advertising, show bills, lithographs, posters or cards of any kind pertaining to the services
performed under this Agreement unless prior written approval has been secured from City to do
otherwise.
23. WAIVER:
A waiver by City of any breach of any term, covenant, or condition contained herein, shall
not be deemed to be a waiver of any subsequent breach of the same or any other term, covenant, or
condition contained herein, whether of the same or a different character.
24. INTEGRATED CONTRACT:
This Agreement represents the full and complete understanding of every kind or nature
whatsoever between the parties hereto, and all preliminary negotiations and agreements of
whatsoever kind or nature are merged herein. No verbal agreement or implied covenant shall be
held to vary the provisions hereof. Any modification of this Agreement will be effective only by
written execution signed by both City and Contractor.
25. INSERTED PROVISIONS:
Each provision and clause required by law to be inserted into the Agreement shall be
deemed to be enacted herein, and the Agreement shall be read and enforced as though each were
included herein. If through mistake or otherwise, any such provision is not inserted or is not
correctly inserted, the Agreement shall be amended to make such insertion on application by either
party.
26. CAPTIONS:
The captions in this Agreement are for convenience only, are not a part of the Agreement
and in no way affect, limit or amplify the terms or provisions of this Agreement.
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Blackberry Farm Golf Course Maintenance 2016
P.O. No.: _________________
IN WITNESS WHEREOF, the parties have caused the Agreement to be executed on the day
and year first above written.
CONTRACTOR CITY OF CUPERTINO
[Name of Contractor] A Municipal Corporation
By By ___________________________
Carol Atwood, Director of Recreation & Community
Services
Name_______________________
Date __________________________
Title
Date________________________
RECOMMENDED FOR APPROVAL:
By____________________________
Address______________________
______________________________ Title
APPROVED AS TO FORM:
By
Colleen Winchester , Acting City Attorney
ATTEST:
_________________________________
Grace Schmidt, City Clerk
Contract Amount: _________________
Account No. : ___________________
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EXHIBIT A
SCOPE OF WORK BLACKBERRY FARM GOLF COURSE MAINTENANCE
Work to provide maintenance of Blackberry Farm Golf Course
1. PUTTING GREENS
1.01 SCOPE: Greens shall be maintained disease and weed free. Complete renovation of any green is not included in this maintenance project.
1.02 MOWING FREQUENCY: Winter –six times per week. Spring/Summer/Fall – six
times per week. Contractor to recycle grass trimmings.
1.03 CHANGING CUPS: Contractor shall change the cup location daily year-round.
Placement is to be at least 8 feet from edge of green on level surface. When
requested, use the 1/3 rule – 1/3 of the pins back, 1/3 pins middle, 1/3 pins up.
1.04 HEIGHT OF CUT: Is to be 0.135 of an inch
1.05 FERTILIZATION: Contractor to collect soil samples yearly to determine
recommended nutrients, rates of application and frequency of application, with the
goal of a sustainable fertility program. Use organic fertilizers, i.e. Earthworks or
approved equivalent. The City shall determine which of the greens are to be tested. Contractor to use Logan Laboratories or City approved equal for soils testing and
recommendations. All fertilizer shall be applied in accordance with all applicable
laws, codes, specifications and policies and at minimum rates that are consistent with
healthy turf.
1.06 AERIFICATION/TOP DRESS/VERTI-CUTTING: Contractor is to perform DryJect aerification or equal twice a year in March/April and September/October, and
overseed with Pencross bentgrass in September. Perform a DryJect Maximus
aerification or equal in July. Verti-cut greens monthly during the growing season.
Top-dress with TD320 from TMT enterprises or City approved equal.
1.07 PESTICIDE APPLICATION: All pesticide application shall be completed by a qualified person in accordance with all applicable laws, codes, specifications and
policies. Greens to be maintained disease and weed free. Apply all chemicals
sparingly. Applications shall be as per EPA regulations. Contractor must possess
SDS (safety data sheets) for all materials. All posting and re-entry requirements must
be followed. Contractor to submit monthly a written report of all pesticide applications. A recommendation by a licensed Pest Control Advisor (PCA) that is
familiar with Blackberry Farm Golf Course and with its setting and protected natural
resources is required for applications, and a licensed staffer with a current Qualified
Applicator License (QAL) or is a Qualified Applicator Certificate holder (QAC) shall
be on site and provide oversight during applications is required. All work shall adhere to all laws, regulations and applicable guidelines for all pesticide applications.
Contractor may be required to obtain a Restricted Materials Use Permit and Notice of
Intent prior to any applications.
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1.08 PROTECTION OF CREEK AND PONDS: No runoff from fertilizer, pesticide or
chemical applications shall flow into creeks or ponds nor to drainage inlets that
discharge to creeks or ponds.
1.09 INTERSEEDING: Contractor shall interseed greens with City approved mix of creeping bentgrass two times per year, in the spring and fall at a rate of 2 lbs. per 1,000 sq. feet unless otherwise directed.
2. COLLAR MAINTENANCE
2.01 MOWING FREQUENCY: Twice weekly in spring/summer/fall and once a week in
winter.
2.02 HEIGHT OF CUT: to be ½ inch all year
2.03 FERTILIZATION: to be fertilized the same as greens
2.04 WEED CONTROL: to be applied the same as greens
3. TEE MAINTENANCE
3.01 MOWING FREQUENCY: Two to three times per week in spring/summer/fall and
one to two times a week in winter.
3.02 HEIGHT OF CUT: to be ½ inch all year
3.03 FERTILIZATION: Contractor to collect at least one soil sample yearly to
determine the recommended complete fertilizer to use. Contractor to use Logan
Laboratories or City approved equal for soils testing and recommendations. Fertilizer
to be applied four times a year in March, May, late August and October. The
application rate shall be at the manufacturer’s recommended rate. All fertilizer shall be applied in accordance with all applicable laws, codes, specification and policies
and at minimum rates consistent with healthy turf. Special care shall be taken to
prevent fertilizer or fertilizer-containing runoff from getting into creek areas or ponds.
3.04 AERIFICATION: Contractor to aerate four times per year in May and October and
as needed.
3.05 OVERSEEDING: Contractor to overseed four times per year with perennial rye
grass, at 8 lbs. per 1,000 sq. feet unless otherwise directed. Contractor to use
seeder/slicer (verti-cutting) unit.
3.06 TEE MARKERS: Contractor shall move and rotate daily. Keep 10 feet apart and 8
feet from back of tee (except where markers do not allow).
3.07 PERMANENT YARDAGE MARKERS: Contractor to keep visible at all times.
3.08 WEED CONTROL: Contractor to apply two broadleaf weed control in the spring
and fall. Broadleaf weed control is for, but not limited to, English Daisy, clover,
spurge and chickweed. Contractor to apply one Crabgrass control in spring. All
weed controls shall be applied in accordance with all applicable laws, codes, specification and policies.
3.09 PROTECTION OF CREEK AND PONDS: No runoff from fertilizer, pesticide or
chemical applications shall flow into creek areas or ponds nor to drain inlets that
discharge to creek areas or ponds.
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3.10 SEED AND TOPSOIL TEES: Contractor to place seeds and sand/organic compost
mix on tees daily to repair divots.
4. FAIRWAY MAINTENANCE
4.01 MOWING FREQUENCY: two to three times per week in growing season, and
one to two times per week in winter
4.02 HEIGHT OF CUT: ¾ inch all year
4.03 FERTILIZATION: Contractor to collect one soil sample yearly to determine the
recommended complete fertilizer to use. Contractor to use Logan Laboratories or
City approved equal for soils testing and recommendations. Fertilizer to be applied
four times a year in March, May, late August and October. The application rate shall be at the manufacturer’s recommended rate. All fertilizer shall be applied in accordance with all applicable laws, codes, specifications and policies and at
minimum rates consistent with healthy turf.
4.04 AERIFICATION: VERTI-CUTTING: Contractor to aerate, verti-cut once per
year in April/May.
4.05 OVERSEEDING: Contractor shall overseed with Perennial Rye one time per year, 8 lbs. per 1,000 sq. feet unless otherwise directed. Use seeder/slicer for distribution.
Perform spot-overseeding as needed with Perennial Rye.
4.06 WEED CONTROL: Contractor to apply broadleaf weed control twice per year, in
the spring and fall. Broadleaf weed control is for, but not limited to, English Daisy, clover, spurge and chickweed. Contractor to apply one Crabgrass control in spring. All weed controls shall be applied in accordance with all applicable laws, codes,
specification and policies.
4.07 PROTECTION OF CREEK AND PONDS: No runoff from chemical applications
shall flow into creek areas or ponds. Contractor shall cover the drain inlets and drainage structures that discharge to the creek for one week after the application of any chemicals.
5. ROUGH MAINTENANCE
5.01 MOWING FREQUENCY: twice per week all year
5.02 HEIGHT OF CUT: 1 to 1 ½ inches all year
5.03 FERTILIZATION:Same as Fairway Maintenance
5.04 AERIFICATION: Same as Fairway Maintenance
5.05 WEED CONTROL:Contractor to apply two broadleaf weed control in the spring
and fall. Broadleaf weed control is for, but not limited to, English Daisy, clover,
spurge and checkweed. Contractor to apply one Crabgrass control in spring. All
weed controls shall be applied in accordance with all applicable, laws, codes, specification and policies.
5.06 PROTECTION OF CREEK AND PONDS:No runoff from chemical applications
shall flow into creeks or ponds.
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7. EQUIPMENT AND EQUIPMENT STORAGE
7.01 GREEN EQUIPMENT: The City encourages the Contractor to use
Environmentally Friendly or Green equipment and supplies for this contract.
7.02 SCOPE: All mowing equipment shall be on a regular preventive maintenance schedule for hydraulic and oil lines so as to minimize damage to turf and protect the
creek and wildlife habitat from leaks. Hydraulic hoses shall be changed off site every
six months.
7.03 GREENS: Mowing equipment shall be 9 or more bladed, reel-type mower with a frequency of cut at a minimum of .25 at 3.6 mph.
7.04 TEES: Mowing equipment shall be 7 or more bladed, reel-type mower with a
frequency of cut at a minimum of .53 at 4.2 mph.
7.05 FAIRWAYS: Mowing equipment shall be 6 or more bladed, reel-type mower with a
frequency of cut at a minimum of .67 at 5.0 mph.
10. PARKING LOT AT GOLF COURSE ENTRANCE
10.01 SWEEPING: Contractor shall sweep monthly. Manually using a blower is acceptable during the hours of 7:00 am to 8:00 pm on week days and 9:00 am to 6:00
pm on weekend, and in accordance with the City’s noise ordinance.
10.02 LOOSE TRASH AND GARBAGE CANS: Contractor shall pick up trash and
check area daily.
10.03 BROKEN GLASS/BOTTLES: Contractor shall pick up and dispose of broken glass or similar potentially harmful materials immediately.
11. CLUBHOUSE & MAINTENANCE BUILDING
11.01 REST ROOMS AT MAINTENANCE BUILDING: Public restrooms for golfers
exist on the golf-facing side of the golf maintenance building. The public rest rooms
will be cleaned and maintained by the City or City’s designee.
11.02 PATIO: Contractor shall sweep daily.
11.03 RECYCLED CARDBOARD CONTAINERs: Shall be emptied at least once per
week.
12. ENTRY AREA/CLUBHOUSE GROUNDS
12.01 FLOWER BEDS: Contractor shall weed, mulch, water and replenish as needed.
12.02 TRASH: Contractor shall pick up daily.
12.03 FOOT BRUSHES: Contractor shall clean and check weekly and replace when worn.
12.04 WALKWAYS: Contractor shall sweep daily when weather permits.
12.05 TRASH AND CIGARETTE CANS: Contractor shall empty cans daily and comply
with City’s recycling standards.
12.06 LEAKS FROM GOLF CARTS: Contractor shall clean immediately.
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12.07 LANDSCAPE SHRUBBERY: Contractor shall trim monthly and as needed.
12.08 ANNUAL PLANTINGS: Contractor shall remove and re-plant minimum 2 times
per year the two planter boxes located at the clubhouse. The planter box on number
one tee measuring roughly 4.5 ft. by 35.5 ft. (160 S.F.) and the planter box to the left of the building along the restroom walkway measuring roughly 8 ft. by 34 ft. (272 S.F.).
12.09 DRIVING RANGE: Contractor shall cut grass weekly and fertilize and aerate the
same as fairways.
12.10 WEED CONTROL (NON-SELECTIVE): Contractor shall use mechanical method of trimming or removing undesirable vegetation in tree wells, perimeter and interior fence lines, barriers, railroad ties, delineators, and along edges of golf play areas that
are along the creek or associated native planting areas.
12.11 LITTER: Contractor shall remove daily.
12.12 TRASH AND DEBRIS (FROM MAINTENANCE): Contractor shall remove as it occurs and dispose of it in a safe and legal manner.
12.13 SOIL, WATER SAMPLES: Contractor shall take samples annually or more often
if unusual growth habits develop.
12.14 RODENT CONTROL: Contractor shall begin immediate eradication action
following local, state and federal guidelines when gopher or ground squirrel activity occurs. Contractor is not allowed to use rodenticides nor any chemicals to control rodents. Acceptable methods may include carbon dioxide use, trapping, exclusion, or
burrow sealing/removal, or using other techniques as acceptable to City.
12.15 SAND TRAPS: Complete renovation of any sand trap is not included in this
maintenance project. Contractor shall rake daily. Contractor shall keep sand at 4 inches in depth minimum and keep clean of all weeds. When using power rake, stay about one foot from edge of trap. When hand-raking edge of trap, put sand inward on
low side and pull outward on high side. Contractor to edge traps monthly and as
needed. Do not drag sand out of trap when exiting trap with power rake.
12.16 TREES: Any tree removal or tree replacement must be approved by the City and any expenditures incurred will be outside the standard scope of work. Contractor shall keep all trees trimmed at least 6 feet from the ground to prevent damage to golf
cart tops and maintenance equipment, except for trees and shrubs along the creek
which shall only be trimmed as acceptable to the City Naturalist. Contractor shall
maintain trees in a safe, healthy, and aesthetically pleasing condition at all times. Contractor shall mow, weed and/or mulch tree wells as needed. Contractors shall immediately remove any broken tree limbs. Downed brush shall be removed as soon
as possible. All trimmings or debris shall be removed from the course, unless they
are chipped, and used for mulch on site. Contractor shall not be responsible for
removal of dead or fallen trees; such removal shall be at the City’s expense unless it
is determined that the condition was caused by the Contractor’s negligence.
12.17 USGA GREEN SECTION VISIT: Contractor shall have a USGA staff agronomist
visit the course yearly on the following schedule: first year in the spring, second year
in the summer, third year in the fall, no winter visits. Contractor shall act on all
appropriate recommendations that result from these visits.
12.18 LEAF PICKUP: Contractor shall remove leaves daily or as necessary.
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12.19 VANDALISM/GRAFFITI: Contractor shall correct vandalism immediately and
remove graffiti within 24 hours.
14. OTHER AREAS
14.01 TEE MARKERS: Contractor shall have two sets each hole. Missing or broken
markers shall be replaced immediately.
14.02 BENCHES/TEE SIGNS: Contractor shall immediately remove any damaged bench,
and notify supervisor so that City can replace it. Any damaged tee sign shall be
removed as soon as possible, and notify supervisor so that City can replace it.
14.03 YARD MARKERS: Contractor shall replace as needed any yard markers.
14.04 GREENS FLAGS, POLE, CUPS: Contractor shall replace flags, poles and cups when they are discolored, frayed or damaged in any way.
14.05 BALL WASHERS: Contractor shall check for water/soap daily. Contractor shall
replace tee towels monthly or more often if towel is frayed, discolored, or
aesthetically unpleasing.
14.06 SAND TRAP RAKES: Contractor shall keep two rakes per trap or more as needed, and replace any missing or broken rake immediately.
14.07 OUT-OF-BOUNDS/HAZARD STAKES: Contractor shall replace white our-of-
bounds stakes immediately if missing or broken.
14.08 OVERSEEDING: Contractor shall spot-overseed with Perennial Rye when needed.
14.09 PONDS: Contractor shall keep the ponds free from algae and excessive growth of plant material.
14.10 BRIDGE: Contractor shall inspect bridge daily for safe conditions and repair
structures immediately when necessary.
14.11 FOOT GOLF: Contractor shall maintain 9 hole foot golf course, with all tee
markers, holes, cups, flagpoles, and flags. Edging around the cups shall be done weekly.
15. IRRIGATION
15.01 SCOPE: Irrigation system shall be maintained in a manner to provide proper watering. Any major irrigation system repairs or improvements are not included in
this maintenance project.
15.02 MAINTENANCE: Contractor shall maintain system, including lateral lines,
sprinkler heads, and controllers in good operating repair, functioning properly, and conforming to related laws, codes and regulations. No valves or water main repairs are included in this maintenance project. Contractor shall notify the City immediately
when valve or water main repairs are necessary for proper operation.
15.03 FREQUENCY: Contractor is to irrigate as required to maintain adequate moisture
for growth rate and appearance. Contractor is to hand-water as needed any and all portions of the course that do not receive adequate water from the irrigation system.
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15.04 TESTING FOR ADEQUATE SOIL MOISTURE: Contractor shall determine by
visual observation, plant resiliency, turgidity, examining cores removed by soil probe,
and moisture sensor devices.
15.05 WATER CONSERVATION: Irrigation controllers shall be programmed to maintain course appearance and health of vegetation while maximizing water conservation.
15.06 WIND PROBLEMS: In areas where wind creates problems of spraying onto private
property or road rights of way, operation shall occur during period of lowest wind
velocity.
15.07 MONITORING: Contractor shall make corrections for coverage, adjustment, clogging of lines, and removal of obstacles, tilting of heads, and management of
plant materials that obstruct the spray as they occur.
15.08 SYSTEM CHECK: Contractor shall check the system daily during months of
operation.
15.09 PUMPING PLANT: Pumping plant shall be maintained the City.
15.10 WATER COST: Water costs shall be paid for by the City.
133
CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1218 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/10/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Application for Alcoholic Beverage License for Yayoi, 20682 & 20684 Homestead Road
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Application
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:ApplicationforAlcoholicBeverageLicenseforYayoi,20682&20684Homestead
Road
RecommendapprovaloftheAlcoholicBeverageLicensetotheCaliforniaDepartmentof
Alcoholic Beverage Control for Yayoi, 20682 & 20684 Homestead Road
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™134
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Alcoholic Beverage License Application, Yayoi, 20682 & 20684 Homestead Road
Recommended Action
Recommend approval of the Alcoholic Beverage Control License to the California
Department of Alcoholic Beverage Control for Yayoi, 20682 & 20684 Homestead Road
Description
Name of Business: Yayoi
Location: 20682 & 20684 Homestead Road
Type of Business: Restaurant
Type of License: 41 – On-Sale Beer and Wine – Eating Place (Restaurant)
Reason for Application: Annual Fee, Original Fee
Discussion
There are no zoning or use permit restrictions which would prohibit the sale of alcohol
as proposed and staff has no objection to the issuance of this license. License Type 41
authorizes the sale of beer and wine for consumption on or off the premises where sold.
This address is located at the corner of Homestead Road and Franco Court in
Homestead Square Shopping Center.
Sustainability Impact
None
Fiscal Impact
None
_____________________________________
Prepared by: Julia Kinst, Planning Department
Reviewed by: Aarti Shrivastava, Assistant City Manager
Approved for Submission by: David Brandt, City Manager
Attachment: A - Application
COMMUNITY DEVELOPMENT DEPARTMENT
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3308 www.cupertino.org
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1252 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/22/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Application for Alcoholic Beverage License for Pieology Pizzeria, 19409 Stevens CreekBoulevard, Suite 140
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Application
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:ApplicationforAlcoholicBeverageLicenseforPieologyPizzeria,19409Stevens
Creek Boulevard, Suite 140
RecommendapprovaloftheAlcoholicBeverageLicensetotheCaliforniaDepartmentof
Alcoholic Beverage Control for Pieology Pizzeria, 19409 Stevens Creek Boulevard, Suite 140
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™139
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Alcoholic Beverage License Application, Pieology Pizzeria, 19409 Stevens Creek
Boulevard, Suite 140
Recommended Action
Recommend approval of the Alcoholic Beverage Control License to the California
Department of Alcoholic Beverage Control for Pieology Pizzeria, 19409 Stevens Creek
Boulevard, Suite 140
Description
Name of Business: Pieology Pizzeria
Location: 19409 Stevens Creek Boulevard, Suite 140
Type of Business: Restaurant
Type of License: 41 – On-Sale Beer and Wine – Eating Place (Restaurant)
Reason for Application: Annual Fee, Original Fees, Federal Fingerprints, State
Fingerprints
Discussion
There are no zoning or use permit restrictions which would prohibit the sale of alcohol
as proposed and staff has no objection to the issuance of this license. License Type 41
authorizes the sale of beer and wine for consumption on or off the premises where sold.
This address is located at Main Street.
Sustainability Impact
None
Fiscal Impact
None
_____________________________________
Prepared by: Julia Kinst, Planning Department
Reviewed by: Aarti Shrivastava, Assistant City Manager
Approved for Submission by: David Brandt, City Manager
Attachment: A - Application
COMMUNITY DEVELOPMENT DEPARTMENT
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3308 www.cupertino.org
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1253 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/22/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Application for Alcoholic Beverage License for Tofu Plus, 10971 North Wolfe Road
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Application
Action ByDate Action ResultVer.
City Council12/1/20151
Subject: Application for Alcoholic Beverage License for Tofu Plus, 10971 North Wolfe Road
RecommendapprovaloftheAlcoholicBeverageLicensetotheCaliforniaDepartmentof
Alcoholic Beverage Control for Tofu Plus, 10971 North Wolfe Road
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™144
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Alcoholic Beverage License Application, Tofu Plus, 10971 North Wolfe Road
Recommended Action
Recommend approval of the Alcoholic Beverage Control License to the California
Department of Alcoholic Beverage Control for Tofu Plus, 10971 North Wolfe Road
Description
Name of Business: Tofu Plus
Location: 10971 North Wolfe Road
Type of Business: Restaurant
Type of License: 41 – On-Sale Beer and Wine – Eating Place (Restaurant)
Reason for Application: Annual Fee, Original Fees, Federal Fingerprints, State
Fingerprints
Discussion
There are no zoning or use permit restrictions which would prohibit the sale of alcohol
as proposed and staff has no objection to the issuance of this license. License Type 41
authorizes the sale of beer and wine for consumption on or off the premises where sold.
This address is located at Cupertino Village Shopping Center at the corner of North
Wolfe and Homestead Roads.
Sustainability Impact
None
Fiscal Impact
None
_____________________________________
Prepared by: Julia Kinst, Planning Department
Reviewed by: Aarti Shrivastava, Assistant City Manager
Approved for Submission by: David Brandt, City Manager
Attachment: A - Application
COMMUNITY DEVELOPMENT DEPARTMENT
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3308 www.cupertino.org
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1254 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/22/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Application for Alcoholic Beverage License for Starbucks #5217, 20520 Stevens CreekBoulevard
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Application
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:ApplicationforAlcoholicBeverageLicenseforStarbucks#5217,20520Stevens
Creek Boulevard
Recommend approval of the Alcoholic Beverage Control License to the California Department
of Alcoholic Beverage Control for Starbucks #5217, 20520 Stevens Creek Boulevard
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™148
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Alcoholic Beverage License Application, Starbucks #5217, 20520 Stevens Creek
Boulevard
Recommended Action
Recommend approval of the Alcoholic Beverage Control License to the California
Department of Alcoholic Beverage Control for Starbucks #5217, 20520 Stevens Creek
Boulevard
Description
Name of Business: Starbucks #5217
Location: 20520 Stevens Creek Boulevard
Type of Business: Restaurant
Type of License: 41 – On-Sale Beer and Wine – Eating Place (Restaurant)
Reason for Application: Annual Fee, Original Fee
Discussion
There are no zoning or use permit restrictions which would prohibit the sale of alcohol
as proposed and staff has no objection to the issuance of this license. License Type 41
authorizes the sale of beer and wine for consumption on or off the premises where sold.
This address is located at the Crossroads Shopping Center at the corner of Stevens
Creek and De Anza Boulevards.
Sustainability Impact
None
Fiscal Impact
None
_____________________________________
Prepared by: Julia Kinst, Planning Department
Reviewed by: Aarti Shrivastava, Assistant City Manager
Approved for Submission by: David Brandt, City Manager
Attachment: A - Application
COMMUNITY DEVELOPMENT DEPARTMENT
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3308 www.cupertino.org
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1255 Name:
Status:Type:Consent Calendar Agenda Ready
File created:In control:11/22/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Application for Alcoholic Beverage License for Yoshida Restaurant, 10700 South De AnzaBoulevard
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Application
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:ApplicationforAlcoholicBeverageLicenseforYoshidaRestaurant,10700SouthDe
Anza Boulevard
RecommendapprovaloftheAlcoholicBeverageLicensetotheCaliforniaDepartmentof
Alcoholic Beverage Control for Yoshida Restaurant, 10700 South De Anza Boulevard
CITY OF CUPERTINO Printed on 11/25/2015Page 1 of 1
powered by Legistar™153
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Alcoholic Beverage License Application, Yoshida Restaurant, 10700 South De Anza
Boulevard
Recommended Action
Recommend approval of the Alcoholic Beverage Control License to the California
Department of Alcoholic Beverage Control for Yoshida Restaurant, 10700 South De
Anza Boulevard
Description
Name of Business: Yoshida Restaurant
Location: 10700 South De Anza Boulevard
Type of Business: Restaurant
Type of License: 41 – On-Sale Beer and Wine – Eating Place (Restaurant)
Reason for Application: Annual Fee, Original Fee
Discussion
There are no zoning or use permit restrictions which would prohibit the sale of alcohol
as proposed and staff has no objection to the issuance of this license. License Type 41
authorizes the sale of beer and wine for consumption on or off the premises where sold.
Sustainability Impact
None
Fiscal Impact
None
_____________________________________
Prepared by: Julia Kinst, Planning Department
Reviewed by: Aarti Shrivastava, Assistant City Manager
Approved for Submission by: David Brandt, City Manager
Attachment: A - Application
COMMUNITY DEVELOPMENT DEPARTMENT
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3308 www.cupertino.org
154
155
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CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1233 Name:
Status:Type:Second Reading ofOrdinances Agenda Ready
File created:In control:11/18/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Second reading of an Ordinance amending Section 2.04.010 of the Cupertino MunicipalCode regarding regular City Council meetings that fall on any Election Tuesday in a regular Cupertinoelection year
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Redline Draft Ordinance
B - Clean Draft Ordinance
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:SecondreadingofanOrdinanceamendingSection2.04.010oftheCupertino
MunicipalCoderegardingregularCityCouncilmeetingsthatfallonanyElectionTuesdayina
regular Cupertino election year
ConductthesecondreadingandenactOrdinanceNo.15-2137:"AnOrdinanceoftheCity
CounciloftheCityofCupertinoamendingSection2.04.010ofChapter2.04ofTitle2ofthe
CupertinoMunicipalCoderegardingregularCityCouncilmeetingsthatfallonanyElection
Tuesday in a regular Cupertino election year"
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OFFICE OF THE CITY CLERK
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-3223 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Second reading of an Ordinance amending Section 2.04.010 of the Cupertino Municipal
Code regarding regular City Council meetings that fall on any Election Tuesday in a
regular Cupertino election year.
Recommended Action
Staff recommends that City Council conduct the second reading and enact Ordinance
No. 15-2137: "An Ordinance of the City Council of the City of Cupertino amending
Section 2.04.010 of Chapter 2.04 of Title 2 of the Cupertino Municipal Code regarding
regular City Council meetings that fall on any Election Tuesday in a regular Cupertino
election year."
Discussion
On November 17, Council conducted the first reading of the ordinance with a further
amendment to automatically move regular City Council meetings that fall on any
Election Tuesday in a regular Cupertino election year to the first Monday of the month.
Sustainability Impact/CEQA
The proposed ordinance is purely procedural; there is no impact to sustainability.
Moreover, these changes are exempt under the California Environmental Quality Act.
Fiscal Impact
There is no fiscal impact resulting from this amendment.
_____________________________________
Prepared by: Grace Schmidt, City Clerk
Approved for Submission by: David Brandt, City Manager
Attachments:
A –Redline Draft Ordinance
B – Clean Draft Ordinance
158
ORDINANCE NO. 15-2137
AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF CUPERTINO
AMENDING SECTION 2.04.010 OF CHAPTER 2.04 OF TITLE 2
OF THE CUPERTINO MUNICIPAL CODE REGARDING
REGULAR CITY COUNCIL MEETINGS THAT FALL ON ANY
ELECTION TUESDAY IN REGULAR CUPERTINO ELECTION NOVEMBER OF
EVEN-NUMBERED YEARS
WHEREAS, the Ordinance is determined to be exempt under provisions and
requirements of the California Environmental Quality Act of 1970, together with related
State CEQA Guidelines (collectively, "CEQA"), in that the amendments involve
procedural administrative changes that will not have a direct or reasonably foreseeable
indirect change to the physical environment; and
WHEREAS, the City Council of the City of Cupertino is the decision-making
body for this Ordinance; and
WHEREAS, the City Council has reviewed and considered the exemption
determination under CEQA prior to taking any approval actions on this Ordinance and
agrees with such exemption; and
NOW, THEREFORE, THE CITY COUNCIL OF THE CITY OF CUPERTINO
DOES HEREBY ORDAIN AS FOLLOWS:
SECTION 1. Section 2.04.010 of Chapter 2.04 of Title 2 of the Cupertino Municipal
Code is hereby amended to read as follows:
2.04.010 Regular Meetings.
The City Council shall hold regular meetings on the first and third Tuesdays of each
month at six forty-five p.m. and may adjourn any regular meeting to a date certain,
which shall be specified in the order of adjournment and when so adjourned, such
adjourned meeting shall be a regular meeting for all purposes. Such adjourned
meetings may likewise be adjourned and any so adjourned meeting shall be a regular
meeting for all purposes.
On regular meeting days, the City Council shall begin any closed session items at six
o'clock p.m.
159
Ordinance No. 15-2137
Page 2
City Council meetings that fall on legal holidays shall automatically be moved to the
following day.
City Council meetings that fall on any Election Tuesday in November of an even-
numbered a regular Cupertino election year shall automatically be moved to the first
Monday of the month.
SECTION 2. The City Clerk shall certify the adoption of this Ordinance and shall
give notice of its adoption as required by law. Pursuant to Government Code Section
36933, a summary of this Ordinance may be published and posted in lieu of publication
and posting of the entire text.
INTRODUCED at a regular meeting of the City Council of the City of Cupertino
the 17th day of November and ENACTED at a regular meeting of the City Council of
the City of Cupertino the 1st of December, 2015, by the following vote:
PASSED:
Vote: Members of the City Council
Ayes:
Noes:
Absent:
Abstain:
ATTEST: APPROVED:
______________________ __________________________________
Grace Schmidt, City Clerk Rod G. Sinks, Mayor, City of Cupertino
160
ORDINANCE NO. 15-2137
AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF CUPERTINO
AMENDING SECTION 2.04.010 OF CHAPTER 2.04 OF TITLE 2
OF THE CUPERTINO MUNICIPAL CODE REGARDING
REGULAR CITY COUNCIL MEETINGS THAT FALL ON ANY
ELECTION TUESDAY IN REGULAR CUPERTINO ELECTION YEARS
WHEREAS, the Ordinance is determined to be exempt under provisions and
requirements of the California Environmental Quality Act of 1970, together with related
State CEQA Guidelines (collectively, "CEQA"), in that the amendments involve
procedural administrative changes that will not have a direct or reasonably foreseeable
indirect change to the physical environment; and
WHEREAS, the City Council of the City of Cupertino is the decision-making
body for this Ordinance; and
WHEREAS, the City Council has reviewed and considered the exemption
determination under CEQA prior to taking any approval actions on this Ordinance and
agrees with such exemption; and
NOW, THEREFORE, THE CITY COUNCIL OF THE CITY OF CUPERTINO
DOES HEREBY ORDAIN AS FOLLOWS:
SECTION 1. Section 2.04.010 of Chapter 2.04 of Title 2 of the Cupertino Municipal
Code is hereby amended to read as follows:
2.04.010 Regular Meetings.
The City Council shall hold regular meetings on the first and third Tuesdays of each
month at six forty-five p.m. and may adjourn any regular meeting to a date certain,
which shall be specified in the order of adjournment and when so adjourned, such
adjourned meeting shall be a regular meeting for all purposes. Such adjourned
meetings may likewise be adjourned and any so adjourned meeting shall be a regular
meeting for all purposes.
On regular meeting days, the City Council shall begin any closed session items at six
o'clock p.m.
161
Ordinance No. 15-2137
Page 2
City Council meetings that fall on legal holidays shall automatically be moved to the
following day.
City Council meetings that fall on any Election Tuesday in a regular Cupertino election
year shall automatically be moved to the first Monday of the month.
SECTION 2. The City Clerk shall certify the adoption of this Ordinance and shall give
notice of its adoption as required by law. Pursuant to Government Code Section 36933,
a summary of this Ordinance may be published and posted in lieu of publication and
posting of the entire text.
INTRODUCED at a regular meeting of the City Council of the City of Cupertino
the 17th day of November and ENACTED at a regular meeting of the City Council of
the City of Cupertino the 1st of December, 2015, by the following vote:
PASSED:
Vote: Members of the City Council
Ayes:
Noes:
Absent:
Abstain:
ATTEST: APPROVED:
______________________ __________________________________
Grace Schmidt, City Clerk Rod G. Sinks, Mayor, City of Cupertino
162
CITY OF CUPERTINO
Legislation Details (With Text)
File #: Version:115-1197 Name:
Status:Type:Ordinances and Action Items Agenda Ready
File created:In control:10/27/2015 City Council
On agenda:Final action:12/1/2015
Title:Subject: Approve actions related to the formation of, and Cupertino’s membership in, the SiliconValley Clean Energy Authority, an independent joint powers authority, which will provide a CommunityChoice Aggregation Program to offer clean energy alternatives for Cupertino residents andbusinesses; and related CEQA action
Sponsors:
Indexes:
Code sections:
Attachments:Staff Report
A - Technical Study Draft Report
B - Community Choice Energy Draft Ordinance
C - Joint Powers Authority Draft Resolution
D - Joint Powers Authority Draft Agreement
Action ByDate Action ResultVer.
City Council12/1/20151
Subject:Approveactionsrelatedtotheformationof,andCupertino’smembershipin,the
SiliconValleyCleanEnergyAuthority,anindependentjointpowersauthority,whichwill
provideaCommunityChoiceAggregationProgramtooffercleanenergyalternativesfor
Cupertino residents and businesses; and related CEQA action
1.AccepttheSiliconValleyCommunityChoiceEnergyTechnicalStudyDraftReport,and
find that the proposed actions are exempt from CEQA; and
2.ConductthefirstreadingoftheOrdinanceNo.15-2138:“AnOrdinanceoftheCity
CounciloftheCityofCupertinoAuthorizingtheImplementationofaCommunity
ChoiceAggregationProgram”tocreateandparticipateintheSiliconValleyClean
Energy Authority; and
3.AdoptResolutionNo.15-111oftheCityCounciloftheCityofCupertinoApprovingthe
Joint Powers Agreement Establishing the Silicon Valley Clean Energy Authority; and
4.AuthorizetheCityManagertoremitupto$450,000,aspreviouslybudgeted,tothe
Silicon Valley Clean Energy Authority to support the initial costs of the Authority; and
5.ApproveanincreasetotheFiscalYear2015-16SustainabilityDivisionSpecialProject
Budget of $100,000 for project contingency as outlined in the JPA; and
6.DirectstafftoreturntoCouncilwithanupdateandpotentialactionregardingbridge
financing for the Authority; and
7.DirectstafftoreturntoCouncilwithaproposaltoprovideinterimprojectand/orstaffing
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File #:15-1197,Version:1
support to the Authority via a separate services agreement; and
8.DirectstafftoreturntoCouncilforappointmentofaregularDirectorandalternate
Director to the Authority’s Board of Directors.
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\ OFFICE OF THE CITY MANAGER
SUSTAINABILITY DIVISION
CITY HALL
10300 TORRE AVENUE • CUPERTINO, CA 95014-3255
TELEPHONE: (408) 777-7603 www.cupertino.org
CITY COUNCIL STAFF REPORT
Meeting: December 1, 2015
Subject
Approve actions related to the formation of, and Cupertino’s membership in, the Silicon
Valley Clean Energy Authority, an independent joint powers authority, which will provide
a Community Choice Aggregation Program to offer clean energy alternatives for Cupertino
residents and businesses; and related CEQA action.
Recommended Action
1. Accept the Silicon Valley Community Choice Energy Technical Study Draft Report,
and find that the proposed actions are exempt from CEQA; and
2. Conduct the first reading of the Ordinance No. 15-2138: “An Ordinance of the City
Council of the City of Cupertino Authorizing the Implementation of a Community
Choice Aggregation Program” to create and participate in the Silicon Valley Clean
Energy Authority; and
3. Adopt Resolution No. 15-111 of the City Council of the City of Cupertino Approving
the Joint Powers Agreement Establishing the Silicon Valley Clean Energy Authority;
and
4. Authorize the City Manager to remit up to $450,000, as previously budgeted, to the
Silicon Valley Clean Energy Authority to support the initial costs of the Authority;
and
5. Approve an increase to the Fiscal Year 2015-16 Sustainability Division Special Project
Budget of $100,000 for project contingency as outlined in the JPA; and
6. Direct staff to return to Council with an update and potential action regarding
bridge financing for the Authority; and
7. Direct staff to return to Council with a proposal to provide interim project and/or
staffing support to the Authority via a separate services agreement; and
8. Direct staff to return to Council for appointment of a regular Director and alternate
Director to the Authority’s Board of Directors.
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Description
Background
Authorized by California law, Community Choice Energy (CCE) enables city and county
governments to pool the electricity demand within their jurisdictions to directly procure or
generate electrical power supplies on behalf of the residents and businesses in their
communities. The main driver for interest in CCE programs in California is the opportunity
to accelerate the shift to renewable and low greenhouse gas (GHG) emitting energy sources
in support of climate action objectives. While electric supply is handled by the CCE
program, the electricity grid and customer service remain with the incumbent utility, or
PG&E in Santa Clara County. Three CCE programs now operate in California - Marin Clean
Energy, Sonoma Clean Power and Lancaster Choice Energy.
In January 2015, the City Council approved Cupertino’s Climate Action Plan (CAP). The
CAP provides a blueprint for the City and its community members to respond to the
sources of and challenges posed by climate change by outlining a menu of actions to reduce
both operational and community greenhouse gas emissions (GHG). It was adopted as a
response to the State of California’s legislative directive (AB 32) for cities to develop local
plans to reduce GHG emissions. CAPs provide a process through which communities can
contribute to the state’s climate protection efforts, recognizing that cities are the population
and business centers where emissions are generated, and local governments can serve as a
direct connector to policies, programs, and infrastructure to reduce these emissions at their
source. Of the more than 200 actions included in Cupertino’s CAP, shifting the energy
portfolio to lower GHG sources is the single most impactful action featured, with
Community Choice Energy identified as the key approach to accomplishing the shift.
Following CAP adoption, the City Manager prioritized the study issue of Community
Choice Energy by utilizing approved funding with the FY 2014/15 Budget to initiate an
initial assessment of a CCE program with three other South Bay agencies: Sunnyvale,
Mountain View and Santa Clara County. The Study included four components: 1) Interest
of other communities in forming a South Bay CCE program; 2) Benefits of forming a CCE
program, including the potential to advance other strategies within the CAP; 3) Costs and
risks to forming a program; and 4) Framework to guide the formation of a CCE program. In
May 2015, staff and the project consultant provided a presentation to the City Council on
the study issue results. The Assessment Report, The Potential for Community Choice
Energy in the Heart of Silicon Valley, was completed by LEAN Energy US. The full report,
which was provided to Council at that May meeting, is also available to the public at
www.cupertino.org/svcleanenergy.
The Partnership
Spurred by discussions among elected officials at the Santa Clara County Cities Association,
the Cities of Sunnyvale, Cupertino and Mountain View and the County of Santa Clara (for
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its unincorporated areas) contributed funding to the aforementioned collaborative study.
With each agency contributing $80,000, the four agencies formed the Silicon Valley CCE
Partnership (SVCCEP – www.svcleanenergy.org), with each serving a project role as
guided by executive leadership. Sunnyvale staff led the project team, and procured the
consultant services needed to support the partnership and to conduct an initial assessment
to assist decision-makers with determining whether and how to move forward with a CCE
program. Cupertino led community outreach and engagement efforts outlined below.
Mountain View is working to review financing options to cover anticipated program start-
up costs and working capital requirements, detailed in the fiscal impact section of this
report.
Upon learning the positive results of the Initial Study, each agency returned to its elected
bodies to request additional funding to complete a Technical Study, the results of which are
shared in Attachment A. Each agency contributed $170,000 and has made a commitment to
fund an additional $350,000 to SVCCEP’s pre-launch activities through their respective
FY15/16 Budget. These funds, and associated SVCCEP staff and contracted activities, have
been carefully reviewed by the partner’s Executive Committee, comprised of City Managers
from each of the four agencies, and Mayor’s Task Force, comprised of Mayors from each of
the four partner agencies.
In addition, eight other small and medium sized communities in Santa Clara County have
stepped forward and expressed interest in the prospect of a multi-jurisdictional CCE.
Campbell, Gilroy, Los Gatos, Los Altos, Los Altos Hills, Monte Sereno, Morgan Hill, and
Saratoga have all taken a requisite preparatory step of authorizing Sunnyvale to request
that PG&E provide detailed electrical data for their jurisdictions. This was essential for
conducting the Technical Feasibility Study, as shared in Attachment A. Further, these
agencies have been engaged through community outreach efforts lead by the Partnership in
their jurisdiction (see Community Engagement Section below) and in the development of the
JPA Agreement through the existing network channels including the Santa Clara County
Cities Association (elected participants) and the Santa Clara County City and County
Manager’s Association (executive leadership).
Interest in the CCE model is spreading beyond Santa Clara County, with more than 20
communities throughout California now evaluating and/or pursuing CCE, including San
Mateo County, Alameda County, and a collaboration among Monterey, Santa Cruz, and
San Benito Counties.
Initial Study Results
Based on the experiences of the Marin and Sonoma programs (launched in 2010 and 2014,
respectively), the Assessment Report found that CCE programs offer many benefits and
programs that can be designed to achieve a variety of public policy and program objectives.
Both CCE programs offer electricity supply portfolios with lower GHG emissions than that
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of PG&E, with customer options for a standard service (with higher renewable energy
ratios than PG&E) and a voluntary program to pay a moderate premium for 100%
renewable energy supply. CCE programs also offer competitive rates. While they are
careful to not promise to always have rates lower than PG&E, both programs are currently
providing lower rates for baseline, greener electricity supply (e.g. 50 percent in Marin and
36 percent in Sonoma).
CCE programs can be designed to also achieve other climate action objectives. Local
investments can be directed to incentivizing solar installations and energy conservation
programs, in addition to promoting innovative approaches that incorporate new
technologies. Both operating programs offer favorable terms for existing and new rooftop
solar installations. Marin Clean Energy has invested in local and in-state renewable projects
totaling more than 225 megawatts (MWs) of new clean power, and resulting in construction
and related vendor jobs. In this way, CCE programs also provide local economic
development benefits. Sonoma is taking a similar path and is also investing in an
innovative 12 MW “floatovolatic” solar array installation atop local irrigation ponds. Marin
recently launched a partnership with Tesla to promote on-property battery storage. Marin
also secured more than $5M from state public purpose programming funds (paid by all
electricity ratepayers) to expand their local energy conservation programs. As such, CCE
programs offer strong opportunities to meet CAP objectives for energy conservation and
local solar programs. Here in the South Bay, there is also enhanced potential for synergies
with Silicon Valley technology companies.
These Assessment Report findings were shared with Council in May and its results served
as the driver for advancing community engagement efforts and commissioning a more
detailed Technical Study, each outlined below.
Community Engagement
Lead by staff from the City of Cupertino and with support from MIG, Inc., the SVCCEP
prepared a comprehensive outreach plan to inform and orient residents, businesses, and
community stakeholders in the work of the Partnership. The goals of this process are to
educate the community about CCE and gather feedback on community priorities and
concerns related to a potential CCE program.
Initial Efforts: In the first phase of the project, a website (www.svcleanenergy.org)
was created to disseminate information about the partnership, the process towards
implementation, news, events, and resources. Resources available on the website
now include the initial assessment report, an animated presentation that serves a
primer for CCE, a fact sheet, and frequently asked questions. Those interested in
keeping up to date with SVCCEP activities and progress can join an email list-serve
from the website. To date, over 225 people have joined this list. For the benefit of
Cupertino residents, two CCE stories have been featured in the Cupertino Scene and
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Mayor Sinks hosted a Periscope session on the issue in October. In addition,
information about CCE is being shared via NextDoor, the Cupertino Chamber
newsletter, Block Leader newsletter, on the City’s website, in the City’s Senior
Center newsletter, and with other relevant stakeholders (Sierra Club’s Cupertino
COOL, schools, Kirsch Center for Environmental Studies, etc.).
Community Meetings: To further engage residents, the SVCCEP has organized a
total of 12 community meetings throughout the County. The first round of six
community meetings introduced the community to the concept of CCE and
presented results from the SVCCEP’s Initial Assessment Report. These introductory
meetings were held in October in Cupertino, Mountain View, Campbell, Sunnyvale,
Gilroy, and San Martin. During the meeting, attendees were invited to participate in
a short pre-and-post poll related to their comfort with the concept of Community
Choice Energy. In hearing from the 100 attendees, the partners have a better
understanding of the community’s preferred outcomes, main concerns, and level of
interest in a CCE program. Based upon the survey results, the vast majority of
attendees (96%) think it is a good idea to create a locally controlled nonprofit to
provide cleaner, greener electricity for you at competitive prices. The majority (77%)
of attendees noted that their interest in CCE is to help reduce their carbon footprint
and most (88%) are willing to pay a premium to have all of their electricity generated
by renewable sources. Also encouraging to the partnership was the insight that most
attendees reported thinking that their friends, family and neighbors would respond
either enthusiastically (35%) to a CCE Program or would be interested in a CCE
Program (59%). Full post-poll results by community are available upon request.
Building on the momentum from the first round of community meetings, the next
round of meetings are being held November through January in the communities of
Cupertino, Morgan Hill, Sunnyvale, Mountain View, San Martin, and Los Altos,
with additional interest from Campbell, Los Gatos, and Saratoga to also host events.
This second round of community meetings will focus on the preliminary results of
the partnership’s Technical Study and provide an update on the partnership’s
activities to date and decision making in the months ahead.
Business Partnership: With assistance from Joint Venture Silicon Valley, the
partnership has also engaged the business community since January 2015 when it
hosted a Business Forum on Community Choice Energy at NetApp in Sunnyvale. A
follow-up webinar on November 4t provided a primer on CCE and an update on the
Silicon Valley CCE Partnership’s formation process and key milestones. The webinar
was designed specifically for a business audience, including facilities, energy and
sustainability professionals at local corporate and commercial organizations. Topics
included how CCE works, where it’s been launched successfully, and what it means
for commercial energy customers. The thirty registrants offered unique perspectives
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during the session’s Q&A pertaining to program design and rate structures most
compelling to this sector. In addition to a series of workshops open to all businesses,
the partnership proposes to work through its next phase of outreach to directly
engage with the largest 100 commercial and industrial energy users through one-on-
one or small group meetings with the help of Joint Venture. In addition, a total of 5-
10 presentations on CCE are being scheduled with Chambers and other interest
groups.
Targeted Outreach: Finally, on November 17th, the SVCCEP hosted a productive
dialogue with key community and organizational leaders to gain their ideas and
learn their concerns regarding the prospect of a Community Choice Energy
program. Attendees had the opportunity to provide feedback on the partnership’s
activities to date, express what’s most exciting about currently operating CCE
programs in California, and describe issues for consideration as the partnership
proceeds. A total of 20 attendees from several environmental and community
organizations participated in the meeting. This audience may serve as a successful
conduit for future outreach activities.
Further, presentations upon request have been given to Sunnyvale Cool, the Moffett
Park Business Group, the Sunnyvale Democratic Club, the JVSV Smart Energy
Enterprise Development Zone (SEEDZ) working group, Cupertino Rotary, and the
Santa Clara County Cities Association.
Technical Study Findings
In November 2014, the City of Sunnyvale on behalf of SVCCEP issued a Request for
Qualifications for technical services to complete a Technical Study for purposes of
describing the potential benefits and liabilities associated with forming a CCE program in
Santa Clara County. Following the outcome of the Initial Assessment Report and Council’s
budget authorization for continued CCE efforts, the Partnership hired Pacific Energy
Advisors (PEA) to complete this work. PEA has extensive experience in CCE program
development in California and has supported the launch of all three operating CCE
programs (Marin, Sonoma, and recent program in Lancaster). The final report, shared in
Attachment A, reflects the results of PEA’s comprehensive analysis, which addresses
prospective CCE operations under a range of scenarios over a ten-year planning horizon,
including the identification of anticipated rate/cost impacts, environmental benefits,
resource composition and economic development amongst other considerations. A
summary of this report is provided below.
SVCCE’s Prospective Customers: Currently, Pacific Gas & Electric (“PG&E”) serves
approximately 240,000 customer accounts within communities of the CCE Study
Partners, representing a mix of residential (≈90%) and commercial (≈10%) accounts.
These customers consume nearly four (4) billion kilowatt hours (“kWh”) of electric
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energy each year. While the majority of customers fall under the residential
classification, such accounts historically consume only 34% of the total electricity
delivered by PG&E while commercial accounts consume the remaining 66%.
SVCCE Supply Scenarios: For purposes of the Study, PEA and the CCE Study
Partners identified three indicative supply scenarios, which were designed to test
the viability of prospective CCE operations under a variety of energy resource
compositions, emphasizing the SVCCE Partnership’s interest in significantly
reducing greenhouse gas emissions (“GHGs”) through increased use of carbon-free
electric energy sources.
o Scenario 1: Match the incumbent investor-owned utility’s (“IOU”), Pacific Gas &
Electric Company (“PG&E”), projected greenhouse gas emissions (“GHGs”)
profile while exceeding PG&E’s projected renewable energy content.
o Scenario 2: Exceed applicable renewable energy procurement mandates by
providing SVCCE customers with a minimum 51% renewable energy content in
year one of program operations, scaling up to 66% in year 10, while also
promoting a 20% reduction in electric energy sector GHG emissions relative to
PG&E’s projected emissions profile by procuring additional GHG-free energy
products.
o Scenario 3: Maximize renewable energy and GHG-free power supplies while
maintaining general parity with PG&E’s projected electric rates throughout the
Study period.
Projected SVCCE Impacts: Based on current market prices and various operating
assumptions, the Study indicates that SVCCE demonstrates the potential for
customer cost savings, significant GHG reductions and economic benefits, as
outlined below:
o Cost Savings: Scenarios 1 and 2 demonstrate the potential for customer cost
savings ranging from 1% to 5%, relative to projected PG&E rates, over the ten-
year study period. Scenario 3, which was designed to maximize clean energy
deliveries to SVCCE customers, maintains general rate parity with PG&E.
o Environmental Benefits: Scenario 1, which was specifically designed to match
the incumbent utility’s projected GHG emissions profile, did not yield any
expected emissions savings. Supply Scenario 2, which was framed to achieve
specified proportionate GHG emission reductions of at least 20% relative to the
incumbent utility, resulted in annual emissions reductions ranging from
approximately 38,000 (Year 1 impact) to 82,000 (Year 10 impact) metric tons.
Scenario 3 yielded the most significant emissions benefits – annual projected
emissions reductions ranged from approximately 112,000 (Year 1 impact) to
352,000 (Year 10 impact) metric tons, a proportionate annual GHG reduction
ranging from 60% (Year 1 impact) to 86% (Year 10 impact) relative to PG&E’s
projected emission profile.
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o Economic Benefits: The prospective SVCCE long-term contract portfolio
includes approximately 340 MW of new generating capacity, all of which is
assumed to be located within California and some of which may be located
within communities of the CCE Study Partners. Based on widely used industry
models, such projects are expected to generate up to 11,000 construction jobs and
as much as $1.4 billion in total economic output. Ongoing operation and
maintenance (“O&M”) jobs associated with such projects are expected to employ
as many as 185 full time equivalent positions (“FTEs”) with additional annual
economic output approximating $30 million. SVCCE would also employ a
combination of staff and contractors, resulting in additional ongoing job creation
(up to 30 FTEs per year) and related annual economic output ranging from $3 to
$9 million.
Risks and Sensitivity Analysis: Sensitivity analyses were performed by PEA to
examine the range of impacts that could result from changes in the assumed base
case. The key variables examined are: 1) power and natural gas prices; 2) renewable
energy prices; 3) low carbon energy prices; 4) PG&E rates; 5) PG&E surcharges; and
6) customer participation/opt-out rates. Additionally, a “small JPA” sensitivity case
was run reflective of minimal community participation in the SVCCE joint powers
agency to test the viability of a much smaller CCE program, and a “perfect storm”
sensitivity was run to examine the cumulative impacts of adverse changes to the key
variables. The sensitivity analysis produced a range of levelized electric rates for the
CCE program and PG&E.
The Technical Study also highlights risks that may be faced by the CCE program as
well as related risk-mitigation measures, including, but not limited to, the following:
o Financial risks to SVCCE’s member municipalities in the unlikely event of
CCE failure;
o Financial risks that may exist in the event that procured energy volumes fall
short of or exceed actual customer energy use;
o Reasonably foreseen legislative and regulatory changes, which may limit a
CCE’s ability to remain competitive with the incumbent utility;
o Availability of renewable and carbon-free energy supplies required to meet
compliance mandates, SVCCE program goals, and customer commitments;
and
o General market volatility and price risk.
Timeline & Next Steps
The graphic below provides a high level summary of the main steps involved in forming a
CCE program that culminates in the provision of service to enrolled customers. Key
implementation activities envisioned for SVCCEP include those related to 1) CCE entity
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formation; 2) regulatory requirements; 3) procurement; 4) financing; 5) organization; and 6)
customer noticing.
JPA Formation: December 2015 – March 2016
Unless the municipal organization that will legally register as the CCE entity already
exists, it must be legally established. Municipalities electing to offer or allow others
to offer CCE service within their jurisdiction must do so by ordinance. The two
existing multi-jurisdictional CCE programs each employ a Joint Powers Authority
structure for program governance. Such a structure offers centralized administration
of the operations and typically representation from each community on the Board of
Directors. The JPA structure also offers a legal and fiscal firewall so that the assets
and liabilities of the CCE program are completely separate from the general funds of
member cities.
Over the past year, the project team facilitated the development of a governance
structure for a CCE program, engaging all twelve agencies in this process. The
results of this effort are embodied in the attached JPA Agreement (Attachment D).
This effort was facilitated by Greg Stepanicich, Esq. (of Richards Watson and
Gershon) who supported the launch of Marin Clean Energy. The JPA documents
developed for the “Silicon Valley Clean Energy Authority” build from those of the
two existing programs, which also have many similarities, with Sonoma having used
the Marin agreement as a model for its own structure. Key features of the Silicon
Valley Clean Energy Authority Agreement include the following:
o Effective Date (2.1) & Initial Participants (2.2) – The Agreement becomes
effective on or prior to March 31, 2016 if executed by at least three Initial
Participants after the adoption of Ordinances as required by the Public Utilities
Code.
o Purpose (2.4) - To study, promote, develop, conduct, operate and manage energy
and energy-related climate change programs
o Board of Directors (4.1) – The Board is comprised of one Director from each
Party. The governing body of each Party appoints a regular Director (from
among the governing body) and an alternate (which need not be from among the
governing body).
o Board Voting (4.9) - actions of the Board on all matters shall require an
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affirmative vote of a majority of all Directors on the entire Board, unless a
supermajority is specified. Two or more Directors may request that a voting
shares vote also be held (4.9.2) which is based upon the Party’s proportional
annual energy use (4.9.3). In such cases, both the vote by Directors and the
voting shares vote must be affirmative for an action to be approved by the Board.
o Funding of Initial Costs (6.3.2) - In the event that the CCE Program becomes
operational, these Initial Costs paid by the Initial Participants shall be
reimbursed by the Authority within four years of the Effective Date.
o Withdrawal (7.1) - The agreement provides opportunities for a Party to
withdraw and describes their ongoing obligations and liabilities where
applicable. Such obligations can include losses to the Authority for the power
contracted to serve a Party’s jurisdiction. An additional provision for early
withdrawal allows that a Party may withdraw should be procurement process
not yield successful results (cleaner energy for rates at or below that of PG&E).
The Board of Directors is targeted to have its first meeting in April 2016.
Regulatory Compliance: January 2016 – November 2016
Before aggregating customers, the CCE program must meet certain requirements set
forth by the California Public Utilities Commission (CPUC). In the case of SVCCE,
an Implementation Plan must be adopted by the JPA, and that Implementation Plan
must be submitted to the CPUC The Implementation Plan must include the
following:
o An organizational structure of the program, its operations, and its funding;
o Ratesetting and other costs to participants;
o Provisions for disclosure and due process in setting rates and allocating costs
among participants;
o The methods for entering and terminating agreements with other entities;
o The rights and responsibilities of program participants, including, but not
limited to, consumer protection procedures, credit issues, and shutoff
procedures;
o Termination of the program; and
o A description of the third parties that will be supplying electricity under the
program, including, but not limited to, information about financial, technical,
and operational capabilities.
A Statement of Intent must be included with the Implementation Plan that provides
for: universal access, reliability, equitable treatment of all classes of customers, and
any requirements established by law or the CPUC concerning aggregated service.
The CPUC has 90 days to complete a review and certify the Implementation Plan.
Following certification of the Implementation Plan, the CCE entity must submit a
registration packet to the CPUC, which includes:
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o An executed service agreement with PG&E, which may require a security
deposit; and
o A bond or evidence of sufficient insurance to cover any reentry fees that may be
imposed against it by the CPUC for involuntarily returning customers to PG&E
service. The current CCE bond amount is $100,000.
The CCE program would be required to participate in the CPUC’s resource
adequacy program before commencing service to customers by providing load
forecasts and advance demonstration of resource adequacy compliance. More
specifically, a start-up CCE program would be required to file a formal load forecast
with the CEC upon execution of a primary supply contract, which triggers a 100%
commitment to program launch.
Procurement: May 2016 – November 2016
Power supplies must be secured several months in advance of commencing service.
Power purchase agreements, with one or more power suppliers, would be
negotiated, typically following a competitive selection process. Services that are
required include provision of energy, capacity, renewable energy and scheduling
coordination.
Financing: April 2016 – October 2016
Funding must be obtained to cover program and Agency start-up activities and
working capital needs. Start-up funding is typically secured early in the
implementation process, as these funds are needed to conduct due diligence,
planning and program development, and other critical activities leading up to
service commencement. Working capital lender commitments should be secured
well in advance, but actual credit drawdown need not occur until 4-6 months prior
to program launch and customer enrollment.
Organizational Formation: April 2016 – February 2017
Initial staff positions would be filled several months in advance of service
commencement to conduct the implementation process. On an interim basis, Parties
are envisioned to provide some functional services to the JPA under separate service
agreements. Initially, internal staff of the CCE program may be relatively small but
this would likely change in the event that the CCE determines to insource various
administrative and operational responsibilities and/or develops and administers
new programs for its customers. Contracts with other service providers, such as for
data management services, would be negotiated and put into effect well in advance
of service commencement.
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Community Engagement & Customer Noticing January 2017 – ongoing
If authorized by agency’s elected bodies to move forward into SVCCE’s pre-launch
activities, the partnership will intensify its outreach efforts. By law, every customer
being enrolled into the CCE program must receive a minimum of four written
notifications prior to program launch. For study purposes, the Technical Feasibility
Study assumes that customers will be enrolled three phases, each comprising a third
of the total customer base, over a 25-month period. Such notices must contain
program terms and conditions as well as opt-out instructions and must be sent to
prospective customers at least twice within the sixty-day period immediately
preceding automatic enrollment. These notices are referred to as “pre-enrollment”
notices. Two additional “post-enrollment” notices must be provided within the
sixty-day period following customer enrollment during the statutory opt-out period.
This costly direct mail campaign will also be paired with more cost-effective social
media, collateral development, traditional advertising, and grassroots organizing
(e.g. tabling at farmers markets, festivals, etc.). The partnership’s cost-share
proposal (Attachment D: JPA Agreement, Exhibit E) anticipates these approaches,
which will be assimilated into a next-phase Outreach Plan, should participation in
the JPA be approved.
Ratesetting & Program Development: November 2016 – ongoing
As a California CCE, SVCCE would have independent ratesetting authority with
regard to the electric generation charges imposed on its customers. Prior to service
commencement, SVCCE would need to establish initial customer generation rates
for each of the customer groups represented in its first operating phase or for all
prospective customers within the CCE’s prospective service territory. SVCCE may
decide to create a schedule of customer generation rates that generally resembles the
current rate options offered by PG&E as has been the case with existing programs.
This practice would facilitate customer rate comparisons and should avoid
confusion that may occur if customers were to be transitioned to dissimilar tariff
options. SVCCE would need to establish a schedule for ongoing rate updates and
changes for future customer phases and ongoing operations.
SVCCE may also choose to offer certain customer-focused programs, such as Net
Energy Metering (NEM), voluntary green pricing and/or feed-in tariff (FIT)
programs, at the time of service commencement. To the extent that SVCCE intends
to offer such programs, specific program design would need to be done in advance
of service commencement.
Sustainability Impact
Cupertino’s Climate Action Plan identifies a suite of measures to achieve targeted emissions
reductions for 2020 (20%), 2035 (50%) and 2050 (80%). This Plan specifically points to
Community Choice Energy as the most impactful and cost-effective measure to achieve
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these emissions targets for our community. Measure C-E-7 specifically identifies the
formation of a Community Choice Energy program and defines a pathway to achieve this
goal and associated emissions reductions. Upon launch, the SVCCEP will enable our
agency to achieve 50 percent of its 2020 greenhouse gas emissions goals.
The decision to proceed with the Joint Powers Authority is exempt from environmental
review because it involves organizational and administrative activities that will not result in
any direct or indirect physical change to the environment. (CEQA Guidelines 15378(b)(5),
15061(b) (3).)
Fiscal Impact
The Technical Feasibility Study concludes that ~$2.9M would be needed to support the
development of SVCCEP, inclusive of initial staff hires, implementation plan development,
procurement, community outreach, utility bond requirement, and the initial customer
notification and enrollment process. A summary of program cost components is shown
below. The JPA will refine these estimates after formation.
Cost Item Amount
Internal Staff $730,000
Technical Consulting and Legal Services $620,000
Marketing and Communications $280,000
Customer Noticing and Mailers $120,000
Security Deposits $40,000
Miscellaneous Administrative and General $95,000
CCE Bond $100,000
Debt Service $720,000
Other Pre-launch Activities $180,000
Total $2,885,000
It is intended that approximately $2M of this amount will be funded by contributions from
participating jurisdictions (shown as Initial Costs in Exhibit E of the JPA Agreement, and
included here as Attachment D) with the remaining $900,000 financed through a bank line
of credit or municipal term loan. Note that these initial can be recovered over a period time
from the operating revenue of CCE program if launched.
Up to now, the Partnership efforts have been funded by the Cities of Cupertino, Mountain
View, and Sunnyvale and County of Santa Clara, with each contributing a total of $170,000
to date. These four lead agencies are envisioned to contribute an additional $350,000 to
support program launch with an additional $100,000 being requested as a contingency to
supplement the Initial Costs of the JPA should multiple Parties decline to join. The JPA also
requires funding contributions from the other eight Initial Participants in lesser amounts.
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In addition, the JPA will require operating capital and significant credit capacity for its
initial power supply contract. The amount is currently projected between $10M-$15M and
will depend on the size of initial program roll out. This credit requirement may be met
through a bank or municipal term loan, with a repayment/refinancing period of 3-5 years. It
is important to note that a portion or all of the initial loan amount will require a credit
guaranty, most often provided by a single or multiple member agencies of the JPA. This
guaranty stays in place until the program is operational, revenues begin flowing into JPA,
and the creditor removes the guaranty requirement. The process for identifying potential
banking partners and securing working capital and the necessary credit for the first energy
contract is beginning under the direction of the current Partnership for presentation and
decision making by the JPA Board.
Beyond the costs associated with forming and operating Silicon Valley Clean Energy, it
should be noted that, based upon the scenarios provided in the Technical Study, this
program has the potential to reduce operational costs for its member agencies, in addition
to the community at large. Should Scenario 2, which offers a modest 3% savings/year over
PG&E rates, be achieved by the program, the City of Cupertino could save up to ~$24,000
on its annual electricity bills. Such rates would also allow the Cupertino Union School
District to achieve ~$60,000 in annual savings. While rate savings cannot be guaranteed at
all times, it is the stated goal of the proposed CCE to offer competitive rates to PG&E,
striving for stable and lower electrical rates over the life of the program.
_____________________________________
Prepared by: Erin Cooke, Assistant to the City Manager & Sustainability Manager
Approved for Submission by: David Brandt, City Manager
Attachments:
A. Technical Study Draft Report
B. Community Choice Energy Ordinance
C. Joint Powers Authority Resolution
D. Joint Powers Authority Agreement
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DRAFT SILICON
VALLEY
COMMUNITY
CHOICE
ENERGY
TECHNICAL
STUDY
11/25/2015 Prepared by Pacific Energy
Advisors, Inc.
This Technical Study was prepared for the Silicon
Valley Community Choice Energy (SVCCE)
Partnership for purposes of forming a Community
Choice Energy (CCE) program, which would
provide electric generation service to residential
and commercial customers located within Santa
Clara County. A detailed discussion of the
projected operating results related to the SVCCE
program is presented herein.
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Draft Silicon Valley Community Choice Energy Technical Study
Draft Silicon Valley Community
Choice Energy Technical Study
PREPARED BY PACIFIC ENERGY ADVISORS, INC.
Table of Contents
EXECUTIVE SUMMARY ............................................................................................................................. 1
SECTION 1: INTRODUCTION .................................................................................................................... 9
SECTION 2: STUDY METHODOLOGY ...................................................................................................... 12
Supply Scenario Overview ........................................................................................................................................... 13
Key Assumptions.............................................................................................................................................................. 15
Multi-Phase Customer Enrollment ................................................................................................................................. 16
Indicative Renewable Energy Contract Portfolio ..................................................................................................... 16
Energy Production Options & Scenario Composition ............................................................................................... 20
Scenario 1: GHG Emissions Parity and Additional Renewable Energy Supply Relative to PG&E ............. 21
Scenario 2: 20% Annual GHG Emissions Reductions; Increased Renewable Energy Procurement ............. 24
Scenario 3: Maximize GHG Emissions Reductions while Maintaining General Rate Parity.......................... 27
Costs and Rates............................................................................................................................................................... 30
Greenhouse Gas Emissions ............................................................................................................................................ 32
Economic Development Impacts ................................................................................................................................... 33
Local Economic Development Benefits Potential .................................................................................................... 36
SECTION 3: SVCCE TECHNICAL PARAMETERS (ELECTRICITY CONSUMPTION) ..................................... 38
Historical and Projected Electricity Consumption ...................................................................................................... 38
Projected Customer Mix and Energy Consumption .................................................................................................. 40
Renewable Energy Portfolio Requirements ............................................................................................................... 41
Capacity Requirements ................................................................................................................................................. 43
SECTION 4: COST OF SERVICE ELEMENTS .............................................................................................. 45
Electricity Purchases........................................................................................................................................................ 45
Renewable Energy Purchases....................................................................................................................................... 45
Electric Generation ......................................................................................................................................................... 47
Transmission and Grid Services ................................................................................................................................... 47
Start-Up Costs ................................................................................................................................................................. 47
Financing Costs ................................................................................................................................................................ 49
Billing, Metering and Data Management .................................................................................................................. 49
Staff and Other Operating Costs ............................................................................................................................... 50
Uncollectible Accounts .................................................................................................................................................... 50
Program Reserves ........................................................................................................................................................... 50
Bonding and Security Requirements ........................................................................................................................... 50
PG&E Surcharges ........................................................................................................................................................... 50
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SECTION 5: COST AND BENEFITS ANALYSIS ......................................................................................... 52
Scenario 1 Study Results ............................................................................................................................................... 52
Ratepayer Costs .......................................................................................................................................................... 52
GHG Impacts ................................................................................................................................................................ 54
Scenario 2 Study Results ............................................................................................................................................... 56
Ratepayer Costs .......................................................................................................................................................... 56
GHG Impacts ................................................................................................................................................................ 57
Scenario 3 Study Results ............................................................................................................................................... 59
Ratepayer Costs .......................................................................................................................................................... 59
GHG Impacts ................................................................................................................................................................ 60
SECTION 6: SENSITIVITY ANALYSES ...................................................................................................... 63
Power and Natural Gas Prices .................................................................................................................................... 63
Renewable Energy Costs ............................................................................................................................................... 63
Carbon-Free Energy Costs ............................................................................................................................................ 64
PG&E Rates ..................................................................................................................................................................... 64
PG&E Surcharges ........................................................................................................................................................... 65
Opt-Out Rates ................................................................................................................................................................. 65
Community Participation (Small JPA) .......................................................................................................................... 66
Perfect Storm ................................................................................................................................................................... 66
Sensitivity Results ............................................................................................................................................................ 66
SECTION 7: RISK ANALYSIS ................................................................................................................... 70
Financial Risks to SVCCE Members ............................................................................................................................. 70
Deviations between Actual Energy Use and Contracted Purchases ..................................................................... 71
Legislative and Regulatory Risk ................................................................................................................................... 72
Availability of Requisite Renewable and Carbon-Free Energy Supplies............................................................ 74
Market Volatility and Price Risk .................................................................................................................................. 75
SECTION 8: CCE FORMATION ACTIVITIES ............................................................................................. 77
CCE Entity Formation ...................................................................................................................................................... 77
Regulatory Requirements .............................................................................................................................................. 77
Procurement ..................................................................................................................................................................... 78
Financing .......................................................................................................................................................................... 78
Organization ................................................................................................................................................................... 78
Customer Notices ............................................................................................................................................................ 78
Ratesetting and Preliminary Program Development ............................................................................................... 78
SECTION 9: EVALUATION AND RECOMMENDATIONS .......................................................................... 80
APPENDIX A: SVCCE PRO FORMA ANALYSES ...................................................................................... 83
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Executive Summary Page 1
EXECUTIVE SUMMARY
This Community Choice Energy (“CCE”) Technical Study (“Study”) was prepared for the Silicon Valley
Community Choice Energy (“SVCCE”) Partnership, by Pacific Energy Advisors, Inc. (“PEA”) under contract with
the City of Sunnyvale, for purposes of describing the potential benefits and liabilities associated with forming
a CCE program in Santa Clara County. Such a program would provide electric generation service to
residential and business customers located within the SVCCE Partner jurisdictions. The SVCCE Partnership is
sponsored by the Cities of Cupertino, Mountain View, and Sunnyvale and the County of Santa Clara. The
Partnership has expanded the scope of the study to include eight additional communities in Santa Clara
County including Campbell, Gilroy, Los Altos, Los Altos Hills, Los Gatos, Monte Sereno, Morgan Hill, and
Saratoga, Campbell, Los Gatos, Monte Sereno, Morgan Hill and Gilroy; these 12 communities comprise the
“CCE Study Partners.”
This Study addresses the potential benefits and liabilities associated with forming a CCE program over a ten-
year planning horizon, drawing from the best available market intelligence and PEA’s direct experience with
each of California’s operating CCE programs – PEA has unique experience with regard to California CCE
program evaluation, development and operation, having provided broad functional support to each
operating CCE, which include Marin Clean Energy (“MCE”), Sonoma Clean Power (“SCP”) and Lancaster
Choice Energy (“LCE”). PEA utilized this direct experience to generate a set of anticipated scenarios for
SVCCE operations as well as a variety of sensitivity analyses, which were framed to demonstrate how certain
changes in the base case scenarios would influence anticipated operating results for the SVCCE program.
SVCCE’s Prospective Customers
Currently, Pacific Gas & Electric (“PG&E”) serves approximately 240,000 customer accounts within
communities of the CCE Study Partners, representing a mix of residential (≈90%) and commercial (≈10%)
accounts. These customers consume nearly four (4) billion kilowatt hours (“kWh”) of electric energy each year.
While the majority of customers fall under the residential classification, such accounts historically consume only
34% of the total electricity delivered by PG&E while commercial accounts consume the remaining 66%. Peak
customer demand within communities of the CCE Study Partners, which represents the highest level of
instantaneous energy consumption throughout the year, occurs during the month of July, totaling 660
megawatts (“MW”). Under CCE service, each of these accounts would be enrolled in the SVCCE program
over a three-phase implementation schedule commencing in early 2017, as later discussed in this Study.
Consistent with California law, customers may elect to take service from the CCE provider or remain with
PG&E, a process known as “opting-out.” For purposes of the Study, PEA utilized current participatory statistics
compiled by the operating CCE programs to derive an assumed participation rate of 85% for the SVCCE
program; the remaining 15% of regional customers are assumed to opt-out of the SVCCE program and would
continue receiving generation service from PG&E. Customer and energy usage projections referenced
throughout this Study reflect such adjustment.
SVCCE Indicative Supply Scenarios
For purposes of the Study, PEA and the CCE Study Partners identified three indicative supply scenarios, which
were designed to test the viability of prospective CCE operations under a variety of energy resource
compositions, emphasizing the SVCCE Partnership’s interest in significantly reducing greenhouse gas emissions
(“GHGs”) through increased use of carbon-free electric energy sources. As described to PEA, many local
agencies within the region have adopted climate action plans, which recognize CCE formation as a viable
opportunity to promote the achievement of targeted GHG reductions. With these considerations in mind, the
following supply scenarios were constructed for purposes of completing this CCE Study:
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Scenario 1: Match the incumbent investor-owned utility’s (“IOU”), Pacific Gas & Electric Company
(“PG&E”), projected greenhouse gas emissions (“GHGs”) profile while exceeding PG&E’s projected
renewable energy content.1
Scenario 2: Exceed applicable renewable energy procurement mandates by providing SVCCE
customers with a minimum 51% renewable energy content in year one of program operations, scaling
up to 66% in year 10, while also promoting a 20% reduction in electric energy sector GHG emissions
relative to PG&E’s projected emissions profile by procuring additional GHG-free energy products.2
Scenario 3: Maximize renewable energy and GHG-free power supplies while maintaining general
parity with PG&E’s projected electric rates throughout the Study period.3
When considering the prospective supply scenarios evaluated in this Study, it should be understood that
SVCCE would not be limited to any particular scenario assessed in this Study; the Study’s supply scenarios
were developed in cooperation with CCE Study Partner leadership for the purpose of demonstrating potential
operating outcomes of a new CCE program under a broad range of resource mixes, which generally reflect
key objectives of the Study participants. Prior to the procurement of any particular energy products, SVCCE
would have an opportunity to refine its desired resource mix, which may differ from the prospective scenarios
reflected herein.
When developing SVCCE’s indicative supply scenarios, PEA was directed to include additional assumptions. In
particular, all scenarios include the provision of a voluntary retail service option that would provide
participating customers with 100% renewable energy (presumably for a price premium); for purposes of this
Study, it was assumed that only a small percentage of SVCCE customers would select this service option (≈2%
of the projected SVCCE customer base), which is generally consistent with customer participation in other
operating CCE programs. In addition, all scenarios assume the availability of current solar development
incentives as well as an SVCCE-administered net energy metering (“NEM”) service option, which could be used
to further promote the development of local, customer-sited renewable resources. PEA was also directed to
exclude the use of: 1) unbundled renewable energy certificates (due to ongoing controversy focused on
environmental benefit accounting for such products); 2) specified purchases from nuclear generation, which is
generally unavailable to wholesale energy buyers, including CCE programs, but represents a significant
portion of PG&E’s energy resource mix4; and 3) coal generation,5 which is a cost-effective but highly polluting
domestic power source.
1 Consistent with California’s Renewables Portfolio Standard (“RPS”) laws, retail sellers of electric energy, including CCEs, must
procure a minimum 33% of all electricity from eligible renewable energy sources by 2020; with the recent enrollment of
Senate Bill 350, California’s RPS procurement mandate has been increased to 50% by 2030.
2 Industry accepted GHG accounting practices generally recognize eligible renewable energy sources as GHG-free. Under
the Scenario 2 portfolio composition, incremental purchases of non-RPS-eligible GHG-free sources, specifically electricity
produced by larger hydroelectric resources (with nameplate generating capacity in excess of 30 megawatts) would be
procured by SVCCE to achieve the noted GHG emissions reductions.
3 Under Scenario 3, the proportion of RPS-eligible renewable energy would achieve specified procurement mandates
throughout the Study period. Similar to Scenario 2, additional GHG-free energy purchases would be made, subject to the
specified rate constraint, in an effort to maximize the proportion of clean energy (e.g., renewable energy plus additional
GHG-free energy) delivered to SVCCE customers.
4 According to PG&E’s 2013 Power Content Label, 22% of total electric energy supply was sourced from nuclear generating
facilities; in 2014, a similar proportion of PG&E’s total electric energy supply was sourced from nuclear generating facilities:
21%, as reflected in PG&E’s Power Source Disclosure Report for the 2014 calendar year.
5 According to the California Energy Commission, approximately 6% of California’s total system power mix is comprised of
electric energy produced by generators using coal as the primary fuel source:
http://energyalmanac.ca.gov/electricity/total_system_power.html.
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Projected Cost Impacts to SVCCE Customers
Based on current market prices and various operating assumptions, as detailed in Section 2: Study
Methodology, the Study indicates that SVCCE would be viable under a broad range of market conditions,
demonstrating the potential for customer cost savings and significant GHG reductions. In particular, Scenarios
1 and 2 demonstrate the potential for customer cost savings ranging from 1% to 5%, relative to projected
PG&E rates, over the ten-year study period. Scenario 3, which was designed to maximize clean energy
deliveries to SVCCE customers subject to general rate parity with PG&E, demonstrated that significant
environmental benefits could be achieved through such a procurement strategy: average GHG emissions
reductions approximating 73% and a renewable energy content of 76% were deemed achievable at rate
parity during the 10-year Study period. As previously noted, none of the prospective supply scenarios
include the use of unbundled renewable energy certificates; renewable energy products will be exclusively
limited to “bundled” deliveries produced by generators primarily located within: 1) California; 2) communities
of the SVCCE Study Partners; and 3) elsewhere in the western United States.
General Operating Projections
When reviewing the pro forma financial results associated with each of the prospective supply scenarios, as
reflected in Appendix A of this Study, the “Total Change in Customer Electric Charges” during each year of
the study period reflects the projected net revenues (or deficits) that would be realized by SVCCE in the event
that the program decided to offer customer electric rates that were equivalent to similar rates charged by
PG&E. To the extent that the Total Change in Customer Electric Charges is negative, SVCCE would have the
potential to offer comparatively lower customer rates/charges, relative to similar charges imposed by PG&E;
to the extent that such values are positive, SVCCE would need to impose comparatively higher customer
charges in order to recover expected costs. Ultimately, the disposition of any projected net revenues will be
determined by SVCCE leadership during annual budgeting and rate-setting processes. For example, in the
cases of Scenario 1 and Scenario 2, each year of the study period reflects the potential for net revenues.
Such net revenues could be passed through to SVCCE customers in the form of comparatively lower electric
rates/charges, as contemplated in this Study, utilized as working capital for program operations in an
attempt to reduce program financing requirements, or SVCCE leadership could strike a balance between
reduced rates and increased funding for complementary energy programs, such as Net Energy Metering,
customer rebates (to promote local distributed renewable infrastructure buildout or energy efficiency, for
example) as well as other similarly focused programs. SVCCE leadership would have considerable flexibility
in administering the disposition of any projected net revenues, subject to any financial covenants that may be
entered into by the program.
Environmental Impacts
With regard to SVCCE’s anticipated clean energy supply and resultant GHG emissions impacts, each
prospective supply scenario yielded progressively increasing environmental benefits, resulting from the
incremental addition of renewable and other GHG-free power sources. For example, Scenario 1, which was
specifically designed to match the incumbent utility’s projected GHG emissions profile (while marginally
exceeding proportionate renewable energy procurement of the incumbent utility), did not yield any expected
emissions savings. Supply Scenario 2, which was framed to achieve specified proportionate GHG emission
reductions relative to the incumbent utility, resulted in annual emissions reductions ranging from approximately
38,000 (Year 1 impact) to 82,000 (Year 10 impact) metric tons. Scenario 3 yielded the most significant
emissions benefits, as current market pricing for renewable and GHG-free power sources allowed for the
significant majority of SVCCE’s projected power resource portfolio to be sourced from these supply options
while still remaining at rate parity with PG&E throughout the 10-year Study period – annual projected
emissions reductions ranged from approximately 112,000 (Year 1 impact) to 352,000 (Year 10 impact)
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metric tons, a proportionate annual GHG reduction ranging from 60% (Year 1 impact) to 86% (Year 10
impact) relative to PG&E’s projected emission profile. With regard to the anticipated GHG emissions impacts
reflected under each scenario, it is important to note that such estimates are significantly influenced by PG&E’s
ongoing use of nuclear generation, which is generally recognized as GHG-free. In particular, the Diablo
Canyon Power Plant (“DCPP”) produces approximately 20% of the utility’s total annual electric energy
requirements. During the latter portion of the Study period, DCPP will need to relicense the facility’s two
reactor units (in 2024 and 2025, respectively) and there is some uncertainty regarding PG&E’s ability to
successfully relicense these units under the current configuration, which utilizes once-through cooling as part of
facility operations – use of once-through cooling is no longer permissible within California, and affected
generators must reconfigure requisite cooling systems or face discontinued operation. To the extent that
PG&E’s use of nuclear generation is curtailed or suspended at some point in the future, SVCCE’s projected
emissions reductions would significantly increase under Scenarios 2 and 3. However, due to the timing of the
relicensing issue facing DCPP, substantive increases to projected environmental benefits (resulting from
prospective changes to PG&E’s nuclear power supply) should not be assumed during the Study period.
The various energy supply components underlying each scenario are broadly categorized as:
Conventional Supply (generally electric generation produced through the combustion of fossil fuels,
particularly natural gas within the California energy markets);
“Bucket 1” Renewable Energy Supply (generally renewable energy produced by generating
resources located within or delivering power directly to California);
“Bucket 2” Renewable Energy Supply (generally renewable generation imported into California);
and
Additional GHG-Free Supply (generally power from large hydro-electric generation facilities, which
are not eligible to participate in California’s RPS certification program).
For the sake of comparison, Table 1 displays PG&E’s proportionate use of various power sources during the
most recent reporting year (2014) as well as the aggregate resource mix within the state of California, as
reported by the California Energy Commission (“CEC”). During the Study period, planned increases in
California’s RPS procurement mandate and various other factors will contribute to periodic changes in the
noted resource mix. Such changes will affect projected GHG emissions comparisons between SVCCE and
PG&E.
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Table 1: 2014 PG&E and California Power Mix
Energy Resource 2014 PG&E Power Mix1 2014 California Power Mix2
Eligible Renewable 27% 20%
--Biomass & Waste 5% 3%
--Geothermal 5% 4%
--Small Hydroelectric 1% 1%
--Solar 9% 4%
--Wind 7% 8%
Coal 0% 6%
Large Hydroelectric 8% 6%
Natural Gas 24% 45%
Nuclear 21% 9%
Unspecified Sources of Power 21% 14%
Total3 100% 100%
1Source: PG&E 2014 Power Source Disclosure Report; 2Source: California Energy Commission; 3Numbers may not add due to rounding.
Projected Economic Development Benefits
SVCCE’s projected long-term power contract portfolio is also expected to have the potential to generate
substantial economic benefits throughout the state as a result of new renewable resource development. A
moderate component of this impact is expected to occur within the local economy as a direct result of
renewable infrastructure buildout to be supported by a SVCCE-administered Feed-In Tariff program, which
could be designed to promote the development of smaller-scale renewable generating projects that would
supply a modest portion of SVCCE’s total energy requirements. The prospective SVCCE long-term contract
portfolio, which is reflected in the anticipated resource mix for each supply scenario, includes approximately
340 MW of new generating capacity (all of which is assumed to be located within California and some of
which may be located within communities of the CCE Study Partners). Based on widely used industry models,
such projects are expected to generate up to 11,000 construction jobs and as much as $1.4 billion in total
economic output. Ongoing operation and maintenance (“O&M”) jobs associated with such projects are
expected to employ as many as 185 full time equivalent positions (“FTEs”) with additional annual economic
output approximating $30 million. SVCCE would also employ a combination of staff and contractors,
resulting in additional ongoing job creation (up to 30 FTEs per year) and related annual economic output
ranging from $3 to $9 million.
Consolidated Scenario Highlights
The following exhibit identifies the projected operating results under each supply scenario in Year 1 of
anticipated CCE operations. Additional details regarding the composition of each supply scenario are
addressed in Section 2.
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The following exhibit identifies the projected operating results under each supply scenario in Year 10 of
anticipated CCE operations. Note that projected reductions in customer savings, which are reflected in Year
10 operating results, substantially relate to the increased use of renewable and other carbon-free resources
throughout the Study period. Such resources are generally more expensive that fossil-fueled power sources
and impose upward pressure on SVCCE’s projected power supply costs, resulting in reduced customer savings.
Key Considerations Scenario1 Scenario 2 Scenario 3
General EnvironmentalBenefits
Renewable energy and GHG content
36% Renewable
63% Total GHG-Free
51% Renewable
70% Total GHG-Free
76% Renewable
85% Total GHG-Free
RateCompetitiveness
Incremental renewable/clean energy purchases will impose
upward pressure on SVCCEcustomer rates
Average 4% savingsrelative to
PG&E rate projections
Average 3% savingsrelative to
PG&E rate projections
Average savingsof <1% relative
to PG&E rate projections
Projected Residential Customer Cost Impacts1
Resource choices will influence monthly energy costs
1Average monthly usage for SVCCE res. customers ≈ 510
kWh
Average $5.09 monthly cost
savingsrelative to PG&E rate
projections
Average $3.49 monthly cost
savingsrelative to PG&E rate
projections
Average $0.76 monthly cost
savingsrelative to PG&E rate
projections
Assumed SVCCE Participation
Projected rate savings/increases are assumedto impact
customer participation levels; medium and large commercial
customers are assumed to be highly cost sensitive
85%customer participation
rate assumed across all
customer groups
85%customer participation
rate assumed across all
customer groups
85%customer participation
rate assumed across all
customer groups
Comparative GHG Emissions Impacts
GHG emissionsimpact relative to assumed PG&E portfolio
0.158 metric tons CO2/MWh
emissions rate is equivalent to
PG&E, resultingin zero
incremental GHG emissions
impacts in Year 1
0.126 metric tons CO2/MWh
emissions rate results in
≈38,000 metric ton GHG
emissions reduction(20%) in
Year 1
0.064 metric tons CO2/MWh
emissions rate results in
≈112,000 metric ton GHG
emissions reduction (60%) in
Year 1
Silicon Valley CCE
Indicative Supply
Scenarios: Year 1
Bucket 1 RE Supply (In-State Supply)
Bucket 2 RE Supply (Imported Supply)Additional GHG-Free Supply
Conventional Supply
Year 1 Scenario 1 Year 1 Scenario 2 Year 1 Scenario 3
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Findings and Conclusions
Based on the results reflected in this Study and PEA’s considerable experience with California CCEs, the
SVCCE program has a variety of electric supply options that are projected to yield both customer rate
savings and environmental benefits. To the extent that clean energy options, including renewable energy and
hydroelectricity, are used in place of conventional power sources, which utilize fossil fuels to produce electric
power, anticipated SVCCE costs and related customer rates would be marginally higher. However, Scenarios
2 and 3 indicate that the potential exists for significant GHG emissions reductions and increased renewable
energy deliveries under a scenario in which SVCCE rates are equivalent (on a projected basis) to or below
similar rates charged by the incumbent utility.
Ultimately, SVCCE’s ability to demonstrate rate competitiveness (while also offering environmental benefits)
would hinge on prevailing market prices at the time of power supply contract negotiation and execution.
Depending on inevitable changes to market prices and other assumptions, which are substantially addressed
through the various sensitivity analyses reflected in this Study, SVCCE’s actual electric rates may be somewhat
lower or higher than similar rates charged by PG&E and would be expected to fall within a competitive
range needed for program viability.
As with California’s operating CCE programs, SVCCE’s ability to secure requisite customer energy
requirements, particularly under long term contracts, will depend on the program’s perceived creditworthiness
at the time of power procurement. Customer retention and reserve accrual, as well as a successful operating
track record, will be viewed favorably by prospective energy suppliers, leading to reduced energy costs and
customer rates. Operational viability is also based on the assumption that SVCCE would be able to secure the
Silicon Valley CCE
Indicative Supply
Scenarios: Year 10
Key Considerations Scenario1 Scenario 2 Scenario 3
General EnvironmentalBenefits
Renewable energy and GHG content
49% Renewable
75% Total GHG-Free
66% Renewable
80% Total GHG-Free
76% Renewable
97% Total GHG-Free
RateCompetitiveness
Incremental renewable/clean energy purchases will impose
upward pressure on SVCCEcustomer rates
Average 3% savingsrelative to
PG&E rate projections
Average 1% savingsrelative to
PG&E rate projections
General rate parity results in
minimal cost impact
Projected Residential Customer Cost Impacts1
Resource choices will influence monthly energy costs
1Average monthly usage for SVCCE res. customers ≈ 510
kWh
Average $4.19 monthly cost
savingsrelative to PG&E rate
projections
Average $1.93 monthly cost
savingsrelative to PG&E rate
projections
Average $0.14 monthly cost
increaserelative to PG&E rate
projections
Assumed SVCCE Participation
Projected rate savings/increases are assumedto impact
customer participation levels; medium and large commercial
customers are assumed to be highly cost sensitive
85%customer participation
rate assumed across all
customer groups
85%customer participation
rate assumed across all
customer groups
85%customer participation
rate assumed across all
customer groups
Comparative GHG Emissions Impacts
GHG emissionsimpact relative to assumed PG&E portfolio
0.109 metric tons CO2/MWh
emissions rate is equivalent to
PG&E, resultingin zero
incremental GHG emissions
impacts in Year 10
0.087 metric tons CO2/MWh
emissions rate results in
≈82,000 metric ton GHG
emissions reduction(20%) in
Year 10
0.015 metric tons CO2/MWh
emissions rate results in
≈352,000 metric ton GHG
emissions reduction(86%) in
Year 10
Year 10 Scenario 1 Year 10 Scenario 2 Year 10 Scenario 3
Bucket 1 RE Supply (In-State Supply)
Bucket 2 RE Supply (Imported Supply)Additional GHG-Free Supply
Conventional Supply
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necessary startup funding as well as additional financing to satisfy program working capital estimates. As
previously noted, it is PEA’s opinion that SVCCE would be operationally viable under a relatively broad
range of resource planning scenarios, demonstrating the potential for customer savings as well as reduced
GHG emissions.
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Section 1: Introduction Page 9
SECTION 1: INTRODUCTION
This Community Choice Energy (“CCE”) Technical Study (“Study”) was prepared for the Silicon Valley
Community Choice Energy (“SVCCE”) Partnership, by Pacific Energy Advisors, Inc. (“PEA”) under contract with
the City of Sunnyvale, for purposes of describing the potential benefits and liabilities associated with forming
a CCE program in Santa Clara County. Such a program would provide electric generation service to
residential and business customers located within the SVCCE Partner jurisdictions, which currently receive
electric service from the incumbent utility, Pacific Gas & Electric Company (“PG&E”). The SVCCE Partnership is
sponsored by the Cities of Cupertino, Mountain View, and Sunnyvale and the County of Santa Clara. The
Partnership has expanded the scope of the study to include eight additional communities in Santa Clara
County; the 12 communities comprise the “CCE Study Partners” and are identified below in Table 2.
Table 2: Prospective SVCCE Member Communities
City of Campbell City of Monte Sereno
City of Cupertino City of Morgan Hill
City of Gilroy City of Mountain View
City of Los Altos City of Saratoga
Town of Los Altos Hills City of Sunnyvale
Town of Los Gatos County of Santa Clara (unincorporated areas)
In consideration of its response to the Sunnyvale’s Request for Qualifications No. F15-49 for Professional
Services to the Environmental Services Department in Association with the Study of Community Choice
Aggregation, which was issued on November 21, 2014, PEA was retained by the City to conduct a technical
study focused on the prospective formation of a CCE program serving communities of the CCE Study Partners.
This Study reflects the results of a comprehensive analysis, which addresses prospective CCE operations under
a range of scenarios, including the identification of anticipated rate/cost impacts, environmental benefits,
resource composition and economic development amongst other considerations. When reviewing this Study, it
is important to keep in mind that the findings and recommendations reflected herein are substantially
influenced by current market conditions within the electric utility industry, which are subject to sudden and
significant changes.
PEA is an independent consulting firm specializing in providing strategic advice and technical support to
various organizations within the California electricity market, particularly aspiring and operating CCE
programs. PEA’s consultants have been assisting local governments with the evaluation and implementation of
CCE programs since 2004, including each of California’s operational CCE programs, which include Marin
Clean Energy (“MCE”), Sonoma Clean Power (“SCP”) and Lancaster Choice Energy (“LCE”). This Study reflects
operating projections that are based on the best available information, utilizing transparent, documented
assumptions to provide an objective assessment regarding the prospects of CCE operation within communities
of the CCE Study Partners. Such assumptions are later discussed in Section 2. However, due to the dynamic
nature of California’s energy markets, particularly market prices which are subject to frequent changes, the
SVCCE Partnership should confirm that the assumptions reflected in this Study generally align with future
market conditions (observed at the time of any decision by the SVCCE Partnership to move forward) to
promote the achievement of early-stage SVCCE operations that generally align with the operating projections
reflected in this Study. To the extent that future market price benchmarks materially differ from any of the
assumptions noted in Section 2 of this Study, PEA recommends updating pertinent operating projections to
ensure well-informed decision-making and prudent action.
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When reviewing this Study, note that the term Community Choice Aggregation (“CCA”), which is referenced
within applicable legislation and related regulations, is currently being used interchangeably with the term
Community Choice Energy (“CCE”)6, a term of art that has been adopted by the SVCCE Partnership to
identify its aggregation initiative. Use of the CCE acronym is becoming increasingly common when referring
to similar customer aggregation programs throughout the state. For purposes of this Study, the term
Community Choice Energy or “CCE” is used when referring to such aggregation programs.
Under existing rules administered by the California Public Utilities Commission (“CPUC”), PG&E would use its
transmission and distribution system to deliver the electricity supplied by SVCCE in a non-discriminatory
manner, as it currently does for its own “bundled service” customers (i.e., customers who receive both electric
generation and delivery services from a single provider) and for “direct access” customers who receive
electricity provided by competitive retail suppliers. PG&E would continue to provide all metering and billing
services, and customers would receive a single electric bill each month from PG&E – each customer’s bill would
show SVCCE charges for generation services as well as charges for PG&E delivery services. Money collected
by PG&E on behalf of SVCCE would be electronically transferred each day to SVCCE’s designated bank
account. Following enrollment in the CCE program, SVCCE customers would continue to be eligible for PG&E-
administered programs funded through distribution rates and public goods charges, including rebate and
subsidy programs focused on energy efficiency and distributed solar generation.
To fulfill the electric energy requirements of its customers and related compliance obligations, SVCCE would
participate in the electricity market to purchase various energy products from qualified generators, brokers,
and/or marketers. In the future, SVCCE may also produce electricity generated by its own power plants,
which could be independently developed or acquired by the CCE. Other programs and services may be
offered by SVCCE as well, such as new programs to promote conservation and/or energy efficiency, locally-
situated distributed renewable generation (e.g., photovoltaic solar systems that are installed by a customer
“behind the meter” to reduce reliance on offsite energy sources and/or reduce overall energy costs), electric
vehicle charging, and customer load shifting (also known as “demand response”).
PEA’s analysis quantifies the expected benefits and liabilities of the CCE program in terms of overall
operating margins, ratepayer costs, reductions in emissions of GHGs, which primarily entail carbon dioxide
(“CO2”) from electric generating resources used to supply customers within communities of the CCE Study
Partners, and economic development impacts arising from new job creation and local spending. The remaining
sections of this report are organized by subject matter as follows:
Section 2: Study Methodology – describes the approach used to conduct the Study.
Section 3: SVCCE Technical Parameters – describes the electric consumption patterns and electric
resource requirements of prospective SVCCE customers (i.e., electricity customers located within
communities of the CCE Study Partners).
Section 4: Cost of Service Elements – explains the various costs that would be involved in providing
electric service through a CCE program.
6 While it is generally understood that both terms refer to the same type of load serving entity, as provided for under the
California Public Utilities Code, PEA is not aware of any current references to the term “Community Choice Energy” or “CCE” in
such Code or applicable regulations. In consideration of this observation, SVCCE should remain aware of this terminology
when communicating with jurisdictional regulatory entities or legislators regarding its prospective aggregation program to
ensure that naming conventions conform with currently applicable laws and regulations which address such programs.
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Section 1: Introduction Page 11
Section 5: Cost and Benefits Analysis – details the estimated benefits and financial liabilities associated
with a variety of potential resource scenarios with regard to ratepayer costs, GHG impacts, and local
economic development impacts.
Section 6: Sensitivity Analyses – describes the variables that are expected to have the largest impact
on customer rates and shows the range of impacts associated with key variables.
Section 7: Risk Analysis – highlights key risks associated with the formation and operation of a CCE
program, including recommended mitigation measures for such risks.
Section 8: CCE Formation Activities – summarizes the steps involved in forming a CCE program.
Section 9: Evaluation and Recommendations – summarizes Study results and provides recommendations
based on PEA’s analysis.
Appendix A: SVCCE Pro Forma Analyses – includes pro forma operating projections for each of the
three SVCCE supply scenarios addressed in this Study.
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SECTION 2: STUDY METHODOLOGY
The analytical framework for the Study is a cost-of-service model that estimates all costs and anticipated
revenues that would be incurred/received in providing CCE services. The Study examines projected CCE
operations over a ten-year study period, including the expected economic/financial impacts related thereto.
As detailed in Section 4 (Cost of Service Elements), CCE program costs include those associated with energy
procurement as well as administrative, financing and other costs that would be involved in the program’s
formation and ongoing operation. Total projected costs over each twelve-month period represent the amounts
that must be funded through program rates, also known as the “revenue requirement.” Average generation
rates of the CCE program, which are calculated by dividing total program costs (dollars) by total program
electricity sales (kilowatt hours, kWh; or megawatt hours, MWh), were determined for each year as well as
the entirety of SVCCE’s ten-year study period (ten-year averages were calculated on a levelized basis, as
further described below) to facilitate comparisons among potential electric supply mixes and against
projected PG&E rates.
The CCE program would have myriad choices with regard to the types of resources that may comprise its
electric supply portfolio. Such choices typically focus on the following portfolio attributes:
1) The proportion of renewable and non-renewable, or conventional, generation sources;
2) Specification of a portfolio GHG emissions rate;
3) Selection of specific generating technologies (solar photovoltaic, wind, geothermal, etc.);
4) Identification of resource locations (local, in-state, regional or a combination thereof);
5) Preferred power supply structure (power purchase agreement or, potentially, asset development/
acquisition);
6) Determination of resource scale (for example, larger “utility-scale” projects and/or smaller distributed
generating resources); and
7) Duration of supply commitments (short-, mid-, long-term).7
Each of these choices presents economic and/or environmental tradeoffs. Specification of initial supply
preferences, which is a fundamental component of the resource planning process, typically occurs during the
implementation and operation stages by those charged with leading and overseeing the CCE program. As
the CCE continues to operate over time, resource planning will remain an ongoing obligation, enabling the
CCE to adapt its planning principles to changing circumstances while promoting the CCE program’s
overarching policy objectives.
For purposes of this Study, PEA developed three representative supply portfolios that were evaluated on the
basis of ratepayer cost, renewable energy content, GHG emissions, and economic development impacts. The
objective of evaluating alternative supply scenarios is to obtain a robust set of analytical results that can be
used to inform decision-makers of the inherent trade-offs that exist among various resource choices while also
illustrating a reasonable range of outcomes that could be achieved through CCE implementation and
operation. It should be understood that SVCCE would not be limited to any particular supply scenario
assessed in this Study; the supply scenarios reflected in this Study have been developed for the sake of
example, taking into consideration key objectives of the aspiring CCE program.
7 For purposes of this Study, a “short-term” supply commitment generally refers to a contract term of one to three years in
duration; a “mid-term” supply commitment generally refers to a contract term of three to ten years in duration; and a “long-
term” supply commitment generally refers to a contract term of ten or more years in duration.
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Supply Scenario Overview
The following supply scenarios are representative of different choices that could be made by SVCCE with
regard to overall renewable energy content, fuel sources and generator locations (of the electric resources
used to supply SVCCE’s customers). Each scenario embodies unique portfolio attributes and related ratepayer
impacts. Subject to compliance with prevailing law and applicable regulations, California CCEs have a broad
range of options when assembling supply portfolios. The three scenarios discussed in this Study also reflect
the inclusion of power supply from both existing generating sources, which may supply the majority of
SVCCE’s early stage energy requirements, and new renewable generation projects developed as a result of
long-term power purchase agreements entered into by the CCE program, which may play an increasingly
prominent role in SVCCE’s mid- and long-term resource planning efforts.
With regard to the specific sources of power supply that were considered as part of this Study, PEA was directed
to exclude the use of: 1) unbundled renewable energy certificates (due to ongoing controversy focused on
environmental benefit accounting for such products); 2) specified purchases from nuclear generation, which is
generally unavailable to wholesale energy buyers, including CCE programs, but represents a significant portion of
PG&E’s energy resource mix; and 3) coal generation, which is a cost-effective but highly polluting domestic
power source. Exclusion of the aforementioned energy products will not only avoid potential controversy
regarding the use of generally objectionable and/or environmentally damaging power sources, but it will
also ensure that SVCCE’s portfolio emissions reporting remains consistent with potential changes in California
law.8 In consideration of this direction, such products were omitted during SVCCE’s portfolio analysis.
It is also noteworthy that independent development and ownership of generating resources may also be an
available supply alternative for the CCE program over the longer-term planning horizon, following years of
successful operations, financial reserve accrual and establishment of general creditworthiness. Because the
timing of any significant CCE-sponsored resource development and ownership likely falls outside the planning
horizon addressed within this Study, PEA has not incorporated SVCCE-owned resources as a component of the
indicative supply scenarios discussed herein. This assumption is largely based on observations related to
California’s operating CCE programs, which have yet to pursue direct investment in generating resources; the
timeline for investment in such resources is likely consistent with PEA’s related assumptions reflected in this
Study.
With regard to the three prospective SVCCE supply scenarios addressed in this Study, such scenarios were
designed to evaluate a broad range of portfolio characteristics for purposes of demonstrating the inherent
tradeoffs that exist when deciding between available resource options. The prospective supply portfolios
were also constructed in consideration of certain key objectives that were communicated to PEA on behalf of
the CCE Study Partners. These objectives generally focused on the achievement of rate competitiveness, GHG
emissions reductions and increased use of renewable energy resources relative to the incumbent utility. Table
3 identifies key planning elements of each scenario addressed in this Study.
8 Assembly Bill 1110 (Ting), which has become a two-year bill, is intended to require the disclosure of portfolio emissions
intensity to California’s retail electricity customers. The proposed methodology for such disclosures would not allow the
inclusion of environmental benefits associated with unbundled renewable energy certificates.
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Table 3: Key Planning Elements of Each SVCCE Indicative Supply Scenario
SVCCE
Supply
Scenario
Primary Objectives of
Supply Portfolio
Total Renewable
Energy Content9 as %
of Total Supply (Year
1; Year 10)
Anticipated GHG
Emissions Savings10
(Year 1; Year 10)
Anticipated SVCCE
Customer Cost
Impacts11 (Year 1;
Year 10)
Scenario 1
Achieve GHG emissions
parity (with PG&E) on a
projected basis while
exceeding PG&E’s
expected proportion of
RPS-eligible procurement
YEAR 1 = 36%
YEAR 10 = 49%
YEAR 1 = No
Change
YEAR 10 = No
Change
YEAR 1 = 4%
average savings
YEAR 10 = 3%
average savings
Scenario 2
Increased RPS-eligible
renewable energy
procurement plus 20%
GHG emissions reductions
(relative to incumbent
utility)
YEAR 1 = 51%
YEAR 10 = 66%
YEAR 1 = 20%
reduction
YEAR 10 = 20%
reduction
YEAR 1 = 3%
average savings
YEAR 10 = 1%
average savings
Scenario 3
Maximize GHG-free
power procurement (RPS-
eligible renewable energy
plus additional GHG-free
supply) while maintaining
general rate/cost parity
YEAR 1 = 76%
YEAR 10 = 76%
YEAR 1 = 60%
reduction
YEAR 10 = 86%
reduction
YEAR 1 = “Zero”
impact
YEAR 10 = “Zero”
impact
Under each of the three supply scenarios, the CCE program would cause new renewable generation projects
to be developed through long-term power purchase agreements. It should be recognized that developing
generation in California is a difficult and time-consuming process, and developing generation within
communities of the CCE Study Partners and surrounding areas may be even more difficult than in other parts
of the state, such as California’s Central Valley. Major development challenges include siting, permitting,
financing and generator interconnection with the transmission system, all of which may take far longer (and
result in higher costs) than originally planned. Suitable sites must be identified and placed under control of
the developer, and the required land can be quite significant, particularly for photovoltaic solar projects.12 It
is also common for proposed generating projects to draw opposition from local residents and interest groups,
who may identify various objections to the project (e.g., habitat destruction/displacement, visual impacts and
species mortality). Once a suitable site is secured and the necessary permits are in place, the project must be
financed, and that financing will primarily depend upon the perceived creditworthiness of the CCE program,
which may take several years to build. As previously noted, PEA has assumed that during the ten year study
horizon, generation projects would be developed and financed by third parties under long-term power
purchase agreements with SVCCE without direct ownership of such projects by the CCE program.
9 All renewable energy volumes are assumed to be eligible for use in California’s Renewables Portfolio Standard (“RPS”)
program.
10 Anticipated GHG emissions impacts were determined in consideration of the GHG emissions factor associated with SVCCE’s
assumed resource mix as compared to the assumed emissions factor associated with PG&E’s supply portfolio, which is expected
to decline throughout the ten-year study period.
11 Anticipated customer cost impacts were determined in consideration of the projected average SVCCE customer rate to be
paid under each of the three prospective supply scenarios relative to the forecasted average PG&E rate.
12 Each MW of PV capacity requires approximately five to eight acres, depending upon the location and installation
characteristics.
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Key Assumptions
When preparing the Study, it was necessary for PEA to incorporate a variety of assumptions, which were
primarily based on current market observations and PEA’s direct experience with California’s operating CCE
programs. Such assumptions were instrumental in deriving SVCCE’s projected operating results, as many
actual data points, such as final contract energy pricing and future customer participation in the SVCCE
program, will not be known until immediately prior to or after service commencement. For purposes of this
Study, the key assumptions identified in Table 4 were incorporated to facilitate the development of SVCCE
operating projections:
Table 4: Key Assumptions Underlying the SVCCE Technical Study
Key Assumption Description
Power Supply Costs Prices for renewable energy and resource adequacy capacity are based on prices
observed for recent transactions and escalated for future periods.
Prices for conventional power supply utilize forward curves based on exchange
quoted futures prices for power, natural gas and GHG emissions allowances.
Fees associated with wholesale scheduling, balancing and settlement with the
California Independent System Operator are based on similar costs experienced by
existing CCE programs.
Capacity requirements and shaped energy requirements were estimated using
monthly customer load data by rate classification as adjusted by PG&E’s hourly class
load profiles.
PG&E Rates PG&E proposed 2016 rates (August Annual Electric True-up) and surcharges (e.g.,
PCIA) were applied to customer load data aggregated by major rate schedule to
form the basis for the PG&E rate forecast.
For future years, the forecast was derived using PG&E’s most recent resource plan,
adjusted for changes to renewable energy content mandated by SB 350.
Forecast of PCIA is based on projected PG&E power portfolio cost and forward
market prices.
It is assumed that CCE would provide similar rate designs and options as PG&E.
Community Participation All twelve municipalities are assumed to participate.
Customer Participation Service is assumed to be offered to all customers except those taking direct access
and standby service. Based on average customer retention experienced by
operating CCE programs, 85% of customers offered service across all customer
classes are assumed to enroll.
CCE Rates & Reserve CCE rates would be set to recover all program costs including power supply,
administration, and debt service as well as funding a reserve equivalent to 4% of
annual program costs.
CCE Operations Staffing and other operating costs were estimated by benchmarking to the three
currently operating CCE programs, with adjustment for differences in the number of
customers served.
Costs associated with administering net energy metering, demand response and
energy efficiency programs were included at $1,275,000 per year.
Bonds and Other Deposits CPUC Bond: $100,000 (Included in Startup Cost)
PG&E Deposit: $40,000 (Included in Startup Cost)
CAISO Deposit: $500,000 (Included in Working Capital)
Supplier Reserve: $2,500,000 (Included in Working Capital)
Startup Costs: $2,900,000
Working Capital: $9,000,000
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Key Assumption Description
Rate Comparisons Rate comparisons are based on the total delivered rate between CCE service and
PG&E service, with the CCE program offering a rate structure that generally parallels
that of PG&E including time-of-use rate differentials that may be applicable under
certain rate schedules (e.g., certain Net Energy Metered customers, which may take
service under rate schedules with time-of-use rate variants). For CCE service, the total
delivered rate includes the CCE charges, PG&E delivery charges, and PG&E
surcharges (e.g., PCIA). For PG&E service, the total delivered rate includes PG&E
generation charges and PG&E delivery charges.
Renewable Portfolio Standards Study assumes the currently applicable renewable energy requirements are
maintained through 2020 and increased to 50% renewable portfolio content by
2030 as mandated by SB 350.
Greenhouse gas emissions rates For PG&E, used its most recent forecast of portfolio emissions rates and adjusted the
rate downwards for future years for the effects of anticipated increase in renewable
energy content. Assumed continued operation of Diablo Canyon Nuclear Power Plant
throughout study period.
For CCE, used the CARB default emissions rate applied to power purchases other than
purchases from renewable and hydro-electric sources.
Voluntary 100% Renewable
Energy Program
Assumed 2% of enrolled customers elect this option.
Multi-Phase Customer Enrollment
For purposes of this Study, PEA assumed a three-phase customer implementation strategy through which that
would enroll customers in the following manner: 1) one-third of prospective SVCCE customers would be
enrolled during the first month of service, drawing from a broad, representative cross section of the entire
SVCCE customer base; 2) another third of the original customer population (i.e., half of the remaining customer
population which had yet to be enrolled) would be transitioned to CCE service during the thirteenth month of
operation, reflecting similar characteristics when compared with the first phase; and 3) all remaining customers
not previously enrolled would be transitioned to CCE service during the twenty fifth month of program
operations. Such a strategy will allow the CCE program to “walk before its runs,” gaining operational
experience while the initial customer base remains relatively small (when compared to the total prospective
customer population). This approach will also create an opportunity for the CCE program to “debug”
potential customer service and billing issues that may arise during initial operations and will also reduce
credit/collateral concerns during initial power contracting efforts. Furthermore, a multi-year phase-in strategy
will serve to minimize initial working capital requirements of the SVCCE program by reducing power contract
payment obligations during early operations, allowing the CCE program to build reserves for purposes of
self-funding future phase-in activities.
Indicative Renewable Energy Contract Portfolio
For purposes of this Study, an indicative long-term renewable energy contract portfolio, which emphasizes
resource and delivery profile diversity in consideration of reasonably available project opportunities, was
assembled for the SVCCE program. For example, a contract portfolio exclusively focused on solar resources
would not provide for requisite energy requirements during the night; similarly, a portfolio focused on the
exclusive use of wind resources would not adequately address SVCCE customer energy requirements during
times of day when wind levels are low. In consideration of the unique generating characteristics associated
with various renewable energy technologies, PEA assembled SVCCE’s indicative renewable energy contract
portfolio for purposes of creating a composite energy delivery profile that would reasonably match the
manner in which SVCCE customers use electric energy. Considerable amounts of solar capacity were
incorporated in the indicative supply portfolio in consideration of robust resource availability throughout
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California and SVCCE’s need for considerable amounts of electricity during peak times of day. Geothermal
and landfill gas-to-energy generating technologies were also incorporated in the supply portfolio, as such
resources have been successfully secured by other CCE programs and provide a stable (“basesload”) energy
delivery profile that only marginally varies over time. Wind generating capacity was also included due to its
availability and general cost effectiveness in serving CCE renewable energy requirements.
This indicative long-term contract portfolio was applied when analyzing each of the three supply scenarios for
purposes of determining the resource planning and financial impacts associated with long-term power supply
commitments that could be reasonably pursued by SVCCE. As reflected in the following table, the indicative
supply portfolio phases in a variety of contracting opportunities over time, allowing the CCE program to
incrementally increase long-term renewable supply commitments without unnecessarily exposing SVCCE to
renewable energy price risk at a single point in time – this is a prudent resource and risk management
practice in consideration of recent, ongoing price reductions that have been observed by California’s
renewable energy buyers. The incremental ramp up in contracted renewable energy volumes will also serve
the purpose of mitigating credit concerns that may impact the CCE program during early operations and limit
the pace at which new long-term resource commitments can be made.
Based on PEA’s experience, California’s three operating CCEs, MCE, SCP and LCE, have been successful in
pursuing small- (1 to 5 MWs in size) to mid-sized (5-40 MWs in size) renewable energy contracting
opportunities during early operations – the developers/owners of such projects have been able to reconcile
credit concerns in consideration of the CCE’s projected operating results and/or relatively nominal collateral
postings. PEA expects that SVCCE would have similar experiences when pursuing available renewable
project options. For example, prior to commencing operations and in the 24 to 36 months thereafter, it is
expected that SVCCE would be able to secure long-term contract commitments with both small- and mid-sized
renewable project opportunities on the basis of SVCCE’s projected operating results. California’s other
operating CCEs have generally been able to pursue similar opportunities with little to no collateral
obligations, utilizing the respective CCE’s pro forma operating projections as the basis for demonstrating
creditworthiness.
After establishing a successful operating track record, SVCCE should be effective in pursuing larger-scale
project opportunities, which may prove to be more cost competitive. PEA expects that larger-scale projects
may be available following the accrual of three or more years of successful operating history, including the
accumulation of prudent financial reserves and the demonstration of significant customer retention – in
general, the opt-out structure provided for by California’s CCE legislation is viewed as a risk by many
prospective project developers and energy sellers; however, the successful operating track record of
California’s existing CCEs and the ongoing compilation of data related to customer participation/retention
has provided compelling evidence that CCE customer counts and overall program operations will remain
stable over time – in general, California’s operating CCEs have each experienced customer retention rates in
excess of 80% with each successive CCE program observing increasing retention rates for its customers. This
trend seems to suggest that improved familiarity with the CCE business model, a growing track record of
success amongst California’s operating CCE programs, and effective marketing campaigns have contributed
to higher levels of customer retention over time.
The indicative portfolio of long-term renewable energy contracts also reflects a significant commitment to
renewable project development within communities of the CCE Study Partners – a total of 20 MWs of
anticipated feed-in tariff (“FIT”) projects has been included in the Study in consideration of the CCE Study
Partners’ interest in promoting local renewable infrastructure buildout and economic development. FIT projects
are typically smaller-scale renewable development opportunities, ranging from 50 kW to 1.5 MW in size, so
PEA has assumed that numerous projects will comprise the 20 MW allocation reflected in the indicative
resource mix.
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For purposes of the Study, PEA has assumed a uniform portfolio of long-term renewable energy contracts for
each of the three indicative supply scenarios. In practical terms, this means that each of the prospective
supply scenarios reflects the resource mix described below as well as varying amounts of additional
renewable and GHG-free energy procured under shorter-term contract arrangements. Such additional
energy volumes will be procured/applied to fulfill each scenario’s specified renewable resource mix.
Assumed prices for such long-term transactions as well as associated capacity factors, which reflect the amount
of energy produced by each resource relative to its total, potential generating capacity, were also
assembled by PEA in consideration of recent renewable energy transactions and typical operating
characteristics associated with the noted renewable resource types. It is also noteworthy that PEA’s pricing
assumptions reflect significant planned reductions in the federal investment tax credit (“ITC”), which is
expected to decrease from 30% to 10% for projects with initial delivery dates occurring after December 31,
2016, as well as growing demand for new renewable energy projects resulting from California’s RPS
procurement mandate increasing to 50% by 203013 – both of these considerations may impose upward
pressure on renewable energy pricing. PEA has addressed this possibility through relatively conservative
price assumptions when compared to the current market for renewable energy products. It is possible, of
course, that Congress could extend the ITC at its current level, which would mean prices for solar power would
be lower than the assumptions used in this study. It is also possible that increased demand, while applying
upward pricing pressure in the near term, may promote expanded supply capabilities, which would have the
effect of mitigating such price pressures over time. The specific contracting opportunities, which have been
incorporated in SVCCE’s indicative long-term renewable energy supply portfolio, are identified below in
Table 5.
Table 5: SVCCE’s Indicative Long-Term Renewable Energy Contract Portfolio
Resource Type Year of First
Delivery Capacity (MW) Capacity Factor** Assumed Price
($/MWh)***
Solar PV, utility scale 2019 100* 30% $65
Solar PV, utility scale 2023 100* 30% $65
Wind 2020 100* 35% $70
Landfill Gas to Energy 2020 10* 90% $80
Landfill Gas to Energy 2025 10* 90% $80
Geothermal 2018 50 100% $80
Solar PV, multiple FIT (local)
projects 2018 5* 22% $100
Solar PV, multiple FIT (local)
projects 2020 5* 24% $90
Solar PV, multiple FIT (local)
projects 2021 5* 24% $90
Solar PV, multiple FIT (local)
projects 2022 5* 24% $90
Total 390 MW
*Denotes assumed new generating capacity to be developed as a result of long-term contracts between SVCCE and qualified renewable project
developers. 340 MW of potential new, California-based renewable generating capacity has been assumed in this Study.
13 On October 7, 2015, Governor Brown signed Senate Bill 350, the Clean Energy and Pollution Reduction Act of 2015. SB
350 increases California’s RPS to 50% by 2030 amongst other clean-energy initiatives. Many details regarding
implementation of SB 350 will be developed over time with oversight by applicable regulatory agencies.
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**Capacity factors quantify the proportionate amount of energy produced by each resource relative to its total, potential generating capacity.
For example, if a 10 MW landfill gas-to-energy generator produced 78,840 MWh per year (relative to its total generating potential of
87,600 MWhs), its capacity factor would be 90%. By comparison, solar generators have relatively low capacity factors (ranging from 20% -
30%, generally), as such generators produce no power at night and very little power during the early morning and late afternoon hours.
***Certain pricing assumptions reflect planned reductions to currently applicable incentives, which may result in increased renewable energy prices
during the ten-year planning period. To the extent that such incentives are continued at current levels and/or supply significantly increases, actual
prices could be lower than reflected herein. It is important to note that a broad range of considerations, including California’s recently increased
RPS (to 50% by 2030), may influence renewable energy pricing and product availability in future years.
Regarding the referenced local solar projects, which are assumed to be developed under an SVCCE-
administered FIT program, the pricing assumptions for such projects were set in consideration of three key
factors:
1) Prices currently available under PG&E’s Electric-Renewable Market Adjusting Tariff (“ReMAT”), which
represents the current construct of PG&E’s FIT program – local project developers would be
evaluating SVCCE’s FIT in consideration of other available alternatives, so it is assumed that SVCCE
would want to offer comparatively higher prices to attract such developers;
2) The assumption that project development costs within SVCCE’s participating jurisdictions generally
exceed project development costs in other locations; and
3) The general interest of the CCE Study Partners in providing meaningful price incentives to promote
local renewable infrastructure buildout.
If such a program is administered by SVCCE, FIT energy prices will need to be sufficiently high to compel
project sponsors to focus development efforts on locally situated project sites – this is the primary purpose of
locally-focused FIT programs. More specifically, PG&E’s ReMAT currently offers eligible, smaller-scale solar
projects a base energy price of $61.23 per MWh.14 This price is adjusted according to a schedule of Time of
Delivery, or “TOD”, factors which generally increase the annual average price paid to participating solar
generators, depending on the quantity of energy produced and delivered during peak times of day (e.g.
weekdays between the hours of 3:00 and 8:00 P.M.). In general terms, the aforementioned base energy
price may translate to a TOD-adjusted average price of more than $70 per MWh, depending on actual
power production. PEA also assumed that project development costs, particularly land costs within the SVCCE
service territory, would be higher than average development costs throughout PG&E’s service territory. With
these observations in mind, as well as the general concept that FIT programs are intended to incentivize local
renewable infrastructure buildout, the prices associated with FIT energy productions were set at comparatively
high levels, ranging from $90-$100 per MWh. Such prices reflect a premium ranging from $25-$35 per
MWh relative to larger projects within optimal development locations.15 While such prices seem sufficient to
promote local FIT interest, it is noteworthy that SVCCE could independently adjust such prices in the event that
actual FIT participation is below (or above) desired levels. In the event that the SVCCE FIT program generates
more interest and participation than originally anticipated, SVCCE could cap the program by implementing a
total capacity ceiling. The cap could always be modified, but implementing a participatory ceiling would
provide an additional layer of financial certainty for the FIT program.
14 PG&E’s Program Period 12 price for As-Available Peaking products, as noted on PG&E’s ReMAT website on October 29,
2015: http://www.pge.com/en/b2b/energysupply/wholesaleelectricsuppliersolicitation/ReMAT/index.page.
15 Note that MCE’s FIT tariff offers similar price incentives to attract local developers. According to MCE’s FIT tariff,
applicable prices are scheduled to incrementally decrease over time (as successive FIT projects enter the project development
queue).
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Energy Production Options & Scenario Composition
When considering the portfolio composition associated with SVCCE’s prospective supply scenarios, several
resource types, including clean (e.g., renewable and GHG-free) and conventional (e.g., fossil-fueled, which
typically entails the use of natural gas within California) energy sources, would be available to supply the
electric energy requirements of SVCCE customers. With regard to renewable energy product options,
California’s currently effective RPS program allows for the use of three distinct renewable energy products,
which are primarily differentiated by unique delivery attributes. In particular, certain RPS-eligible renewable
energy products are referred to as “bundled renewable energy,” meaning that the physical electricity and
renewable attributes (i.e., Renewable Energy Certificates, or “RECs”) are both delivered to the buyer,
whereas other RPS-eligible products are referred to as “unbundled,” meaning that the renewable attributes,
or RECs, are sold separately from the electric commodity. Under the nomenclature of California’s RPS,
bundled renewable energy products are categorized as Portfolio Content Category 1 (“PCC1” or “Bucket 1”)
or Portfolio Content Category 2 (“PCC2” or “Bucket 2”). In general terms, PCC1 products are the most costly,
least objectionable and offer the most flexibility when complying with California’s RPS procurement
mandates. Unbundled renewable energy, or Portfolio Content Category 3 (“PCC3” or “Bucket 3”), has usage
limitations under the RPS program and is also the subject of ongoing philosophical debate regarding
environmental impacts. For purposes of this Study, PEA was advised to exclude unbundled renewable energy
products from SVCCE’s prospective supply portfolios. For purposes of this Study, it was assumed that all
additional GHG-free energy (i.e., GHG-free energy obtained from sources that are not RPS-eligible due to
size limitations) would be produced/delivered by hydroelectric generators. In consideration of these product
options, SVCCE’s three prospective supply scenarios were constructed with the resource preferences reflected
in Table 6.
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Table 6: SVCCE’s Scenario-Specific Energy Resource Preferences
SVCCE
Supply
Scenario
Primary Objectives
of Supply Portfolio
Total Renewable
Energy Content16
as % of Total
Supply (Year 1;
Year 10)
Total PCC1-
Eligible17
Renewable Energy
Content as % of
Total Supply (Year
1; year 10)
Total PCC3-
Eligible18
Renewable Energy
Content as % of
Total Supply (Year
1; year 10)
Total GHG-Free
Energy Content19
as % of Total
Supply (Year 1;
Year 10)
Scenario 1
Achieve GHG
emissions parity
(with PG&E) on a
projected basis
while exceeding
PG&E’s expected
proportion of RPS-
eligible
procurement
YEAR 1 = 36%
YEAR 10 = 49%
YEAR 1 = 27%
YEAR 10 = 44%
YEAR 1 = None
YEAR 10 = None
YEAR 1 = 63%
YEAR 10 = 75%
Scenario 2
Increased RPS-
eligible renewable
energy
procurement plus
20% GHG
emissions reductions
(relative to
incumbent utility)
YEAR 1 = 51%
YEAR 10 = 66%
YEAR 1 = 38%
YEAR 10 = 57%
YEAR 1 = None
YEAR 10 = None
YEAR 1 = 70%
YEAR 10 = 80%
Scenario 3
Maximize GHG-
free power
procurement (RPS-
eligible renewable
energy plus
additional GHG-
free supply) while
maintaining
general rate/cost
parity
YEAR 1 = 76%
YEAR 10 = 76%
YEAR 1 = 57%
YEAR 10 = 64%
YEAR 1 = None
YEAR 10 = None
YEAR 1 = 85%
YEAR 10 = 97%
Scenario 1: GHG Emissions Parity and Additional Renewable Energy Supply Relative to PG&E
Scenario 1 was structured for the primary purpose of matching the projected GHG emissions profile
associated with PG&E’s supply portfolio while also exceeding PG&E’s proportionate level of renewable
energy procurement. With regard to renewable energy procurement, resource preferences within Scenario 1
were generally selected to promote compliance with the legal requirements of California’s RPS in advance of
16 All renewable energy volumes are assumed to be RPS-eligible for purposes of this Study.
17 Portfolio Content Category 1, or “Bucket 1” eligible renewable energy resources, are typically located within California but
may also be located outside California, delivering power to California delivery points via specified energy scheduling
protocols.
18 Portfolio Content Category 3, or “Bucket 3” eligible renewable energy resources, are typically referred to as “unbundled
renewable energy certificates” or “unbundled RECs”. Bucket 3 products are produced when metered renewable energy is
delivered to the grid and represent the environmental and/or “green attributes” associated with such renewable energy
production. However, Bucket 3 products are sold separately from the physical energy commodity without any associated
energy delivery obligations for the seller(s) of such products.
19 Total GHG-free content equals the proportion of total supply produced by renewable energy resources plus the proportion
of total supply produced by non-GHG emitting generating resources, namely non-RPS qualifying hydroelectric generators.
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applicable deadlines.20 In particular, Scenario 1 incorporates a 36% RPS-eligible renewable energy supply
from day one of CCE program operations, incrementally increasing after the 2020 calendar year in
consideration of California’s transition to a 50% RPS mandate. For purposes of Scenario 1, PCC3 and
nuclear volumes were excluded from the renewable energy supply portfolio, replacing such volumes with
additional PCC1 and PCC2 products. This substitution has the effect of increasing total renewable energy
supply costs but will likely minimize philosophical objections related to the use of unbundled renewable
energy products, which have become more prominent in recent years. Additional clean energy purchases,
which would have the effect of reducing overall GHG emissions associated with SVCCE supply portfolio, were
also incorporated, yielding a 63% GHG-free resource mix in Year 1, increasing to 75% in Year 10. A
supply portfolio reflecting such a resource mix would be expected to promote highly competitive customer
rates during the study period but also the lowest level of environmental benefits amongst the three
prospective supply scenarios. The expected clean energy content associated with Scenario 1 is identified in
Table 7, which reflects the proportionate share of purchases relative to SVCCE’s expected energy
requirements.
Table 7: Scenario 1 - Proportionate Share of Planned Energy Purchases Relative to SVCCE’s Projected
Retail Sales
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10
PCC 1 Supply 27% 27% 27% 35% 35% 36% 42% 43% 44% 44%
PCC 2 Supply 9% 9% 9% 2% 4% 6% 1% 2% 2% 4%
PCC 3 Supply 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Total Renewable
Energy Supply 36% 36% 36% 38% 39% 41% 43% 45% 47% 49%
Additional GHG-
Free Energy Supply 27% 29% 31% 32% 31% 30% 29% 28% 27% 26%
Total Clean Energy
Supply 63% 65% 68% 69% 70% 71% 72% 73% 74% 75%
Conventional
Energy Supply
(including CAISO*
market purchases)
37% 35% 32% 31% 30% 29% 28% 27% 26% 25%
*“CAISO” refers to the California Independent System Operator, the organization responsible for overseeing operation of California’s wholesale
electric transmission system and related energy markets. Energy purchases from the CAISO market are not associated with specific generating
resources. As such, CAISO purchases are also commonly referred to as “Unspecified Sources of Power” or “Market Purchases” due to the fact
that these purchases are made from a pool of generating resources administered by the CAISO. Note that it is very common for CCEs to
incorporate considerable quantities of Market Purchases in their respective supply portfolios (20% to 40%, for example). As previously
indicated, PG&E’s power supply portfolio included 21% Market Purchases in 2014. Note that numbers may not add due to rounding.
As previously noted, each indicative supply scenario reflects a uniform portfolio of long-term renewable
energy supply contracts, which incorporates a variety of generating technologies and related energy delivery
profiles. In consideration of the expected delivery start dates and energy quantities associated with each
prospective contract, SVCCE’s portfolio composition will somewhat change over time, reflecting increased
resource diversity.
20 State law requires PG&E to increase its renewable energy content to 33% by 2020. Based on PG&E’s recent Power
Source Disclosure Report, which addressed power purchases and sales completed by the utility during the 2014 calendar
year, its current renewable energy content is approximately 27%. An equivalent renewable supply percentage should be
reflected in PG&E’s 2014 Power Content Label, which was provided to customers of the utility in a recent bill insert.
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Snapshots of the Scenario 1, Year 1 resource mix as well as the related Year 10 resource mix are shown in
the following figures.
Figure 1: Scenario 1 Resource Mix, Year 1
Figure 2: Scenario 1 Resource Mix, Year 10
Figure 3 shows how composition of the Scenario 1 supply portfolio changes throughout the study period,
reflecting planned diversification of SVCCE’s renewable energy supply portfolio through long-term
contracting efforts and local infrastructure build out.
Conventional Energy
Contracts
26%
CAISO Purchases
11%
Short Term Renewable
Energy Contracts
36%
Other Carbon Free Energy Contracts
27%
Conventional Energy
Contracts
18%
CAISO Purchases
8%
Other Carbon Free Energy Contracts
26%
Short Term
RenewableEnergy Contracts
10%
Small Solar PPA
1%
Small Biogas
(LFG) PPA
2%
Wind PPA
8%
Solar PPA
14%
Geothermal PPA
12%
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Figure 3: Scenario 1 Load and Resource Projections
Scenario 2: 20% Annual GHG Emissions Reductions; Increased Renewable Energy Procurement
Scenario 2 reflects more aggressive procurement of renewable energy resources, starting out at a 51% RPS-
eligible renewable energy content, increasing to 66% by Year 10 of program operations. This renewable
energy procurement strategy ensures that SVCCE will continually exceed California’s RPS mandate, even
following recent adoption of the 50% renewable energy procurement requirement. In addition to the noted
renewable energy volumes, Scenario 2 assumes that SVCCE will procure additional GHG-free energy supply
in sufficient quantities to achieve 20% annual reductions throughout the Study period (relative to projected
emission rates of the incumbent utility). As with Scenario 1, the Scenario 2 supply portfolio excludes the use of
PCC3 products and nuclear power. Table 8 details the annual resource composition for Scenario 2 during the
10-year planning period.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
1 2 3 4 5 6 7 8 9 10
GW
H
Year
SILICON VALLEY CCE
Loads and Resources
Renewable, Long Term Renewable, Short Term Other Carbon Free Conventional Contracts CAISO Purchases Loads
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Table 8: Scenario 2 - Proportionate Share of Planned Energy Purchases Relative to SVCCE’s Projected
Retail Sales
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10
PCC 1 Supply 38% 38% 38% 45% 46% 47% 53% 54% 57% 57%
PCC 2 Supply 13% 13% 13% 6% 7% 9% 5% 6% 6% 9%
PCC 3 Supply 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Total Renewable
Energy Supply 51% 51% 51% 51% 53% 56% 58% 61% 63% 66%
Additional GHG-
Free Energy
Supply
19% 21% 23% 25% 23% 21% 19% 18% 16% 14%
Total Clean Energy
Supply 70% 72% 74% 76% 76% 77% 78% 78% 79% 80%
Conventional
Energy Supply
(including CAISO
market purchases)
30% 28% 26% 24% 24% 23% 22% 22% 21% 20%
Figure 4: Scenario 2 Resource Mix, Year 1
Conventional Energy
Contracts
21%
CAISO Purchases
9%
Short Term Renewable
Energy Contracts
51%
Other Carbon Free Energy
Contracts
19%
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Figure 5: Scenario 2 Resource Mix, Year 10
Conventional Energy Contracts
15%
CAISO Purchases
6%
Other Carbon Free Energy
Contracts
14%
Short Term Renewable
Energy Contracts
28%
Small Solar PPA1%
Small Biogas (LFG) PPA
2%
Wind PPA8%Solar PPA14%Geothermal PPA
12%
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Figure 6 shows how composition of the Scenario 2 supply portfolio changes throughout the study period.
Figure 6: Scenario 2 Load and Resource Projections
Scenario 3: Maximize GHG Emissions Reductions while Maintaining General Rate Parity
Scenario 3 represents a supply portfolio that substantially relies on renewable and other GHG-free power
sources to achieve the primary objective of maximizing GHG emissions reductions (relative to related
projections for PG&E) while maintaining general rate parity with the incumbent utility. The Scenario 3
resource mix contributes to the achievement of this objective by incorporating a diversified mix of shorter- and
longer-term supply agreements with a variety of generating technologies. Similar to Scenarios 1 and 2,
PCC3 and nuclear power products are not incorporated in this supply scenario. Throughout the Study period,
the projected Scenario 3 resource mix reflects a fixed renewable energy percentage equating to 76% of
total SVCCE customer energy requirements. Additional GHG-free power sources are layered on top of
planned renewable energy purchases, resulting in proportionate GHG-free supply that begins at 85% in
Year 1 and gradually increases to 97% in Year 10 of projected SVCCE operations. As a result of this
planning strategy, the GHG emissions associated with Scenario 3 are comparatively low, reflecting average
annual reductions (relative to PG&E) approximating 73% throughout the 10-year Study period. Table 9
provides additional detail regarding the indicative resource mix for Scenario 3.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
1 2 3 4 5 6 7 8 9 10
GW
H
Year
SILICON VALLEY CCE
Loads and Resources
Renewable, Long Term Renewable, Short Term Other Carbon Free Conventional Contracts CAISO Purchases Loads
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Table 9: Scenario 3 - Proportionate Share of Planned Energy Purchases Relative to SVCCE’s Projected
Retail Sales
Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10
PCC 1 Supply 57% 57% 57% 64% 63% 61% 66% 65% 66% 64%
PCC 2 Supply 19% 19% 19% 12% 13% 14% 10% 10% 9% 11%
PCC 3 Supply 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%
Total Renewable
Energy Supply 76% 76% 76% 76% 76% 76% 76% 76% 76% 76%
Additional GHG-
Free Energy
Supply
10% 12% 14% 16% 17% 18% 19% 19% 20% 21%
Total Clean Energy
Supply 85% 87% 90% 91% 92% 93% 94% 95% 96% 97%
Conventional
Energy Supply
(including CAISO
market purchases)
15% 13% 10% 9% 8% 7% 6% 5% 4% 3%
Figure 7: Scenario 3 Resource Mix, Year 1
Conventional Energy
Contracts11%
CAISO Purchases
4%
Short Term Renewable
Energy Contracts
76%Other Carbon Free Energy
Contracts
10%
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Figure 8: Scenario 3 Resource Mix, Year 10
Conventional Energy
Contracts
3%
Other Carbon Free Energy
Contracts
21%
Short Term Renewable
Energy Contracts
38%
Small Solar PPA
1%
Small Biogas (LFG) PPA2%
Wind PPA
8%
Solar PPA
14%Geothermal PPA
12%
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Figure 9 shows how composition of the Scenario 3 supply portfolio changes throughout the study period.
Figure 9: Scenario 3 Load and Resource Projections
Costs and Rates
For each supply scenario, detailed estimates were made for electric power supply costs and all other
program costs. Net ratepayer costs or benefits were calculated for each scenario as the difference between
the costs ratepayers would pay while taking service under the CCE program and the costs ratepayers would
pay under bundled service, as currently provided by PG&E. Competitive rates are a key metric for program
feasibility as SVCCE must offer competitive rates in order to retain customers that are automatically enrolled
in the program. Customer retention may also be affected by SVCCE offering customized rate choices such as
voluntary green pricing programs or market based rate options for large end users.21
Rate competiveness is particularly important during the first year, when opt out notices are being provided to
eligible customers and initial impressions are being formed in the community. Generally speaking, if the net
customer cost of SVCCE service is below what the customer would otherwise pay for PG&E bundled service,
the SVCCE program could be considered to offer competitive rates and would be viable with regard to this
important metric. Rates that provide for a modest cost increase may also be considered competitive, if the
“quality” of the retail electricity product offered by SVCCE was meaningfully higher than existing option(s)
21 Such customized rate options would require SVCCE design and administration, working collaboratively with customers and
interested stakeholders. Green pricing participation may also improve SVCCE’s environmental benefits and overall renewable
energy content.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
1 2 3 4 5 6 7 8 9 10
GW
H
Year
SILICON VALLEY CCE
Loads and Resources
Renewable, Long Term Renewable, Short Term Other Carbon Free Conventional Contracts CAISO Purchases Loads
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provided by the incumbent utility – in this context, the term “quality” generally refers to specific attributes of
an electric supply portfolio, including renewable energy content, GHG emissions impacts and complimentary
customer programs, that create measurable distinctions between two available service alternatives. To the
extent that the attributes associated with SVCCE service are perceived as superior to the attributes associated
with PG&E service, then certain cost increases may not impose significant impacts to the overall level of
customer participation in the CCE program. More specifically, a materially higher renewable energy content
and/or lower carbon intensity for the electricity sold by SVCCE may justify a higher price, and SVCCE rates
may be viewed as competitive so long as such rates do not deviate substantially from the PG&E benchmark.
Historically, PG&E generation rates have trended upwards as shown in Figure 10, but the recent decline in
wholesale energy costs are expected to result in lower generation rates beginning in 2016. When reviewing
the following figure, it is important to note that myriad factors can influence power prices over time, including
weather patterns and natural disasters, infrastructure outages, natural gas storage levels and other
considerations. All of these factors contribute to the volatile nature of electric power prices. When reviewing
Figure 10 note that PG&E’s “System Average Generation Rate” represents the average power price paid by
the composite of all customer groups (e.g., residential, commercial, etc.).
Figure 10: PG&E System Average Generation Rates
The primary measure of ratepayer costs calculated for this Study is the difference in total electric rates
between the CCE program and PG&E. This measure examines the change in customers’ total electric bills,
including PG&E delivery charges and PG&E surcharges (namely, “exit fees” associated with PG&E’s
uneconomic generation commitments). In order to compare ratepayer costs over the ten-year study period,
during which electric rates change from year-to-year, PEA calculated levelized electric rates on a per kWh
basis for each SVCCE supply scenario and for PG&E bundled service. In simple terms, a levelized rate allows
for the comparative evaluation of a multi-year period through the use of a single value or metric, which
reflects the year-over-year changes that may occur over such period of time. The development of a levelized
6.0
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7.9
8.6
9.7
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5.0
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6.5
7.0
7.5
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8.5
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9.5
10.0
20
0
5
20
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6
20
0
7
20
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8
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9
20
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PG&E Reported Generation Average Rate
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electric rate utilizes net present value analysis to consolidate rate-related impacts, which occur over time, in a
single number. For purposes of this Study, a levelized rate represents the constant electric rate that would
yield equivalent revenues (in present value terms) if charged to customers in place of the projected series of
annual rates occurring throughout the ten-year study period. Levelized costs are commonly used in the electric
utility industry to provide an apples-to-apples comparative basis for projects that have cash flows occurring
at different points in time. Comparing levelized total electric rates for the CCE program against levelized
total electric rates for PG&E service provides a simple measure of ratepayer impacts over the entire ten-year
study period. Annual impacts are also provided for each scenario and provide a more detailed picture of
ratepayer impacts from year to year of program operations.
Greenhouse Gas Emissions
Each supply scenario was evaluated based on the emissions of greenhouse gases associated with electricity
production as compared to similar projections prepared by PG&E (for its own supply portfolio). Based on
PEA’s review of PG&E’s projected annual GHG emissions factors, which have been prepared through
calendar year 2020, consideration appears to have been given to the impacts of California’s increasing RPS
procurement mandates. PG&E’s projected emissions factor steadily declines through the 2020 calendar year
as additional renewable energy purchases and other prospective clean-energy purchases increase with time.
PG&E’s GHG emissions factor projections for the five-year period beginning in 2016 through 2020 are
identified in the Table 1022:
Table 10: PG&E GHG Emission Factor Projections (2016 through 2020)
Year Emission Factor (lbs
CO2/MWh)
Emission Factor (Metric
Tons CO2/MWh)
2016 370 0.168
2017 349 0.158
2018 328 0.149
2019 307 0.139
2020 290 0.131
For the balance of the ten-year study period, PEA assumed incremental emission reductions for the PG&E
supply portfolio in consideration of increases to California’s RPS procurement mandate and other factors, such
as the launch of other California-based CCE programs, which may have the effect of reducing PG&E’s GHG
emissions factor (via reductions in short-term conventional energy purchases due to declining retail sales).23
PEA’s assumed annual GHG emissions factors for the PG&E supply portfolio, over the balance of the ten-year
study period, are reflected in Table 11:
22 PG&E, Greenhouse Gas Emission Factors: Guidance for PG&E Customers, April 2013.
23 In practical terms, it is not likely that PG&E would materially adjust renewable energy purchases or reduce carbon-free
generation (from its hydroelectric and/or nuclear generators) as a result of customer departure following SVCCE formation.
These carbon-free resources would generally remain in the PG&E supply portfolio without near-term adjustments for departing
load. Instead, it is more likely that PG&E would reduce the amount of conventional market purchases with comparatively high
emissions intensities, which would have the effect of marginally reducing its portfolio emissions factor following customer
departures as the relative proportion of clean energy sources in the PG&E supply portfolio would incrementally increase.
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Table 11: PEA’s Projected GHG Emission Factors for the PG&E Supply Portfolio (2021 through 2025)
Year Emission Factor (lbs
CO2/MWh)
Emission Factor (Metric
Tons CO2/MWh)
2021 280 0.127
2022 272 0.123
2023 264 0.120
2024 256 0.116
2025 248 0.112
The PG&E emissions profile was selected as the benchmark for comparison to promote a conservative
assessment of direct emissions impacts related to CCE operations (on a head-to-head basis with PG&E’s
anticipated supply portfolio). The GHG impacts associated with SVCCE’s supply portfolio will likely be
evaluated (by members of the public and, potentially, through new emissions reporting requirements that may
be incorporated in annual Power Content Label, or “PCL”, reporting) relative to the PG&E benchmark, which
suggests that the aforementioned comparative methodology is appropriate.
For each supply scenario, the difference in GHG emissions produced by the scenario’s assumed resource mix
and the otherwise applicable PG&E supply portfolio were quantified during each year as well as the entirety
of the ten-year study period. The GHG impacts were quantified in terms of total tons of CO2 emissions.
Economic Development Impacts
A key potential benefit of a CCE program is its ability to promote economic development through investment
in and contracts with locally constructed renewable generating infrastructure. Such projects have the potential
to stimulate a significant level of new economic activity within California by creating new jobs and spending
activities during generator construction, ongoing operation and maintenance. Economic development impacts
may also be significant factors when comparing expected operating costs, including generation costs, of the
CCE program to electric generation costs under PG&E service, particularly when initial “head-to-head” cost
comparisons are comparable. When performing such comparisons, it is important to acknowledge the
difficulty in accurately quantifying actual economic benefits related to local project investment, particularly
induced economic impacts resulting from the effects of economic multipliers.
In qualitative terms, it is reasonable to assume that new development projects would stimulate new economic
activity. However, as with any capital project, quantifying the specific location in which such economic benefits
may occur, including job creation, is challenging due to numerous uncertainties affecting the proportion of
expenditures and employment that would occur within discretely defined geographic boundaries. Certain
tools, which rely on the application of industry-specific economic multipliers, have been developed to assist in
completing these projections, but decision makers should be aware of the broad range of outcomes that may
actually apply when interpreting analytical results.
To quantify the economic impacts associated with new renewable generation projects that were incorporated
in the indicative long-term renewable energy supply portfolio that was applied in each of the three energy
supply scenarios, PEA utilized the National Renewable Energy Laboratory’s (“NREL”) Jobs & Economic
Development Impact (“JEDI”) models. NREL is the principal research laboratory for the United States
Department of Energy (“DOE”) Office of Energy Efficiency and Renewable Energy and also provides
research expertise for the Office of Science, and the Office of Electricity Delivery and Energy Reliability.
NREL is operated for DOE by the Alliance for Sustainable Energy, LLC.24
24 National Renewable Energy Laboratory website, http://www.nrel.gov/about/, September 2, 2015.
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NREL JEDI models are publicly available, spreadsheet-based tools that were specifically designed to
“estimate the economic impacts of constructing and operating power plants, fuel production facilities, and
other projects at the local (usually state) level. JEDI results are intended to be estimates, not precise
predictions. Based on user-entered project-specific data or default inputs (derived from industry norms), JEDI
estimates the number of jobs and economic impacts to a local area that can reasonably be supported by a
power plant, fuel production facility, or other project.”25 Unique JEDI models have been developed for a
variety of resource types, including wind, solar, geothermal, biogas and various other generating
technologies. Each version of the model may be downloaded free of charge from NREL’s website:
http://www.nrel.gov/analysis/jedi/download.html.
According to NREL, the JEDI models are peer reviewed and are intended to project gross job estimates. NREL
also notes that it “performed extensive interviews with power generation project developers, state tax
representatives, and others in the appropriate industries to determine appropriate default values contained
within the models.” In PEA’s opinion, NREL’s JEDI models are the appropriate tools to forecast “order of
magnitude” local economic development impacts associated with a CCE program serving communities of the
CCE Study Partners.
Based on the aforementioned indicative long-term renewable energy contract portfolio that was assumed to
exist under each of the three supply scenarios, PEA downloaded, populated and ran the appropriate JEDI
models to derive estimates of the anticipated jobs and economic development impacts that could be created
in relation to the indicative long-term contract portfolio. PEA utilized each set of economic development
projections to assemble an aggregate economic impact analysis for the complete long-term contract portfolio.
However, all economic development estimates within this report are presented with the understanding that
subtle changes in certain expenditures (and jobs) may result in significant changes to actual economic
development impacts.
Key output from the JEDI models is presented within three specific categories: jobs, earnings and economic
output. Within each of these broadly defined categories, JEDI models approximate the impacts of economic
multipliers by quantifying the “ripple effect” that occurs as a result of new local economic activity. JEDI models
initially estimate direct economic impacts at the project site and apply economic multipliers, derived from the
U.S. Bureau of Economic Analysis, the U.S. Census Bureau and other sources, to approximate impacts within the
supply chain (manufacturing job creation, as an example) as well as induced economic impacts (spending that
occurs as a result of activity within the first two categories) related to the project. JEDI models also address
job creation and economic impacts on a temporal basis, quantifying related impacts during two specific
phases of the project lifecycle: 1) construction; and 2) ongoing operation and maintenance.
Forecasted economic impacts associated with the indicative long-term contract portfolio are presented in
aggregate form, inclusive of all anticipated development/contract opportunities, by summing the project-
specific impacts calculated by the JEDI models. This approach facilitates a high-level understanding of the
prospective economic impacts that could be created through such contracts but does not address temporal
nuance related to the timing and creation of economic benefits associated with specific projects. For example,
the unique economic impacts of projects that will begin operation/delivery during the period extending from
2018 through 2025 have been aggregated and presented within a single scenario-specific summary table.
When reviewing economic development projections within this Study, it is important to distinguish between
economic impacts related to the construction period and the ongoing operation and maintenance period. All
job creation estimates are presented as full time equivalent positions (“FTEs”). Projections related to the
25 National Renewable Energy Laboratory website: http://www.nrel.gov/analysis/jedi/about_jedi.html, September 2, 2015.
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construction period are intended to capture annual economic benefits received during the defined construction
term (24 months, for example; note that actual construction periods may vary from project to project).
Economic impacts during the ongoing operation and maintenance period are presented on an annual basis
and are projected to persist throughout the project lifecycle. Aggregate jobs and economic development
impacts associated with the indicative long-term contract portfolio, which would result in the assumed
development and construction of approximately 340 MW (as previously reflected in Table 5, above) of new
renewable generating capacity within the state are reflected in Table 12.
Table 12: SVCCE Economic Development Benefits Potential
As reflected in the previous table, the indicative long-term contract supply portfolio, which is assumed to exist
in each of the CCE program’s three planning scenarios, would result in significant economic benefits throughout
the state and, potentially, within communities of the CCE Study Partners. It is also noteworthy that all jobs
reflected in the previous table are assumed to be additive relative to the status quo. More specifically, PEA
assumes that jobs created through new generator development and construction as well as ongoing
maintenance activities will not displace existing jobs. Furthermore, it is also reasonable to assume that SVCCE
would have little impact on the current PG&E workforce, including those individuals employed to operate and
maintain the utility’s distribution infrastructure, provide customer service, operate existing generating facilities
and myriad other responsibilities within the utility. To date, PEA is not aware of any specific evidence linking
CCE formation and operation to diminished utility employment. In practical terms, the significant majority of
utility functions remain unchanged following CCE formation while the responsibilities associated with a very
small subset of utility positions may change somewhat in consideration of the coordination required between
the incumbent utility and CCE suppliers.
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With respect to the prospective generating facilities that have been incorporated in SVCCE’s indicative long-
term contract portfolio, PEA assumed that the significant majority of such facilities would be developed in
optimal renewable resource areas throughout California. PEA also assumed the development of 20 MW of
locally situated renewable generating projects, which would be developed during the study period under
long-term contract arrangements between SVCCE and third-party project developers (under an assumed
SVCCE-administered FIT program) – such projects are discussed below. With regard to anticipated
development projects occurring in areas outside of jurisdictions comprising the CCE Study Partners, PEA
assumed that virtually all plant equipment, including turbines and other materials, would be procured outside
of the CCE Study Partners’ communities. This equipment typically represents the largest single line item
expenditure in generator construction. Requisite labor, including general site preparation and ancillary
facility construction activities (concrete footings and structures not directly involved in the generation process)
would also draw from California’s broader regional workforce. When considering the following economic
development benefits potential, note that virtually all impacts – other than those associated with the Local
Economic Development Benefits Potential, discussed in the similarly named subsection (below) – are assumed to
accrue in areas outside of Santa Clara County. With this in mind, only a relatively small portion of the total
potential economic development benefits are assumed to accrue within Santa Clara County.
In total, SVCCE’s indicative long-term contract portfolio is projected to result in the creation of approximately
9,000-11,000 new jobs during the aggregate construction period required to complete the assumed 340
MW of new generating projects. During the construction period, individuals working directly on the projects,
including electricians, engineers, construction workers and heavy equipment operators, attorneys and
permitting specialists, would be responsible for as much as $475 million in new economic output of which as
much as $290 million would be collected in the form of salaries and wages. Workers involved with supply
chain activities, such as turbine manufacturing and assembly, cement producers and heavy equipment rental
companies would be responsible for up to $600 million in new economic activity of which approximately
$250 million would be collected in the form of salaries and wages. Furthermore, spending by the
aforementioned individuals (as a result of salary and wage collection) would “induce” other local economic
impacts at local businesses, including restaurants, grocery stores, gas stations and other providers of goods
and services, totaling as much as $300 million of which approximately $110 million would be collected as
salaries and wages. In total, the locally developed generation projects identified under SVCCE’s indicative
long-term contract portfolio would result in approximately $1.26 to $1.38 billion in new economic output
throughout the state and local economy during the construction process.
During ongoing operation of the renewable generators, it is projected that as many as 185 new jobs would
be created with a total annual economic impact ranging from $18 to $28 million. It is anticipated that these
jobs would remain effective as long as the generating facilities remain operational, resulting in significant,
lasting impacts to the local economies of the CCE Study Partners.
Local Economic Development Benefits Potential
The primary source of local jobs and economic development impacts would be derived through projects
developed under SVCCE’s anticipated FIT program, which would promote the construction of locally situated,
smaller-scale (i.e., up to 1 MW of total generating capacity, per project) renewable generating projects over
a period of five to seven years (and beyond, should SVCCE choose to expand this program after initial
participatory limitations are achieved). Note that the 1 MW capacity limitation has been referenced in
consideration of the FIT programs currently administered by MCE and SCP. To the extent that SVCCE’s
governing board determines to specify different project limitations for its FIT program, this would be
permissible. However, SVCCE should be aware that projects in excess of 1 MW may result in additional
administrative complexities due to generator registration and scheduling requirements (with the CAISO)
imposed on projects in excess of the 1 MW capacity threshold. For purposes of this Study and in
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consideration of a similar FIT program offered by MCE, PEA assumed that SVCCE would eventually (by year
five of program operation) support the development of approximately 20 MW of locally situated renewable
generating capacity, which will likely utilize the photovoltaic solar generating technology. PEA acknowledges
that a fairly aggressive FIT buildout schedule has been incorporated in the Study. However, growing
familiarity with the CCE business model and an increasing appreciation amongst project developers for the
financial viability of operating CCEs, as well as decreasing prices to be paid under PG&E’s FIT (or “ReMAT”)
program, have catalyzed recent interest in CCE-administered FIT programs. In fact, interest in MCE’s FIT has
jumped over the past year with more than 6 MW of locally situated renewable generating capacity (out of
MCE’s total FIT participatory cap of 10 MW) actively operating or under development (with related FIT
contracts in place between the developers of such projects and MCE). Ultimately, many factors may affect
SVCCE’s FIT buildout schedule, including the availability of project financing to interested project developers,
actual project interconnection timelines (for most projects, interconnection will be pursued under a PG&E-
administered process, which is subject to delays), price competitiveness and other factors. To the extent that
SVCCE’s FIT buildout schedule is delayed, noted economic development benefits will be deferred until such
projects can be completed.
Based on applicable JEDI modeling results, the prospective SVCCE FIT program would result in the creation of
more than 370 local jobs during generator construction with as many as 500 additional jobs created through
supply chain and induced (during the construction period) economic activity over a period ranging from five to
seven years, depending on the actual period of time required to complete construction activities. As
previously noted, these construction jobs are temporary, but there is also a nominal level of ongoing support
for jobs supporting requisite operation and maintenance activity, which is projected to be approximately six
full-time equivalent employees during each year of facility operation (which may continue for 25-30 years).
Project development would also generate nearly $23 million in earnings for those working on the FIT projects,
which is expected to create a total economic stimulus approximating nearly $40 million (in consideration of
economic multiplier effects created by the spending of earnings/wages). Supply chain and induced impacts
would also be significant totaling approximately $26 million and $71 million, respectively.
It is also anticipated that SVCCE would employ 10 to 30 internal staff, depending on decisions related to
outsourcing/insourcing of requisite activities, during program implementation and ongoing operation. These
estimates were derived by PEA in consideration of direct experience working with California’s operating CCE
programs. Depending on staffing levels, aggregate direct salaries for such staff are estimated to range from
$1 to $3 million per year with a total of $3 to $9 million in total annual local economic activity generated by
SVCCE staff.
These local economic development impacts are subsumed in the aggregate economic development impact
totals reflected in the previous table. It is also noteworthy that PEA attempted to contact NREL regarding
certain wage-related assumptions that are included in the various JEDI models, specifically whether or not
prevailing wages are reflected in such assumptions. In spite of PEA’s efforts, NREL has been non-responsive.
To the extent that prevailing wage requirements are imposed in any project-specific power purchase
agreement, it is reasonable to assume that earnings and related economic development impacts may
somewhat increase to the extent that NREL’s wage assumptions are lower than applicable prevailing wages.
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SECTION 3: SVCCE TECHNICAL PARAMETERS (ELECTRICITY
CONSUMPTION)
Historical and Projected Electricity Consumption
Total electric consumption for eligible customers within communities of the CCE Study Partners was provided
by PG&E for the 2013 and 2014 calendar years. The PG&E historical data was used as the basis for the
study’s customer and electric load forecast. Based on PEA’s review of the PG&E data set, there were
244,205 electric customers within the potential CCE service territory. These customers consumed
approximately 4,771 million kilowatt-hours of electricity during the 2014 calendar year. It is noteworthy that
the aforementioned customer account and usage statistics include approximately 765 accounts, which are
currently served through direct access service arrangements with third party suppliers. These customers
account for approximately 17% of the aforementioned energy consumption, or approximately 799 million
kWh annually, within communities of the CCE Study Partners. Such usage has been excluded from the
projections reflected in this Study – under direct access service arrangements, which are no longer available
to California consumers26, individual customers typically engage in shorter-term contract arrangements for the
provision of electric generation service. By enrolling direct access accounts in the SVCCE program, such
customers would be potentially exposed to duplicate generation charges and/or may be in violation of
existing supply agreements. In consideration of these potential issues, direct access accounts have been
excluded from SVCCE’s prospective customer base. Table 13 summarizes customer account totals and
historical annual energy use within communities of the SVCCE Study Partners. When reviewing the statistics
reflected in Table 13, note that the historical annual electricity usage within communities of the CCE Study
Partners is more than double MCE’s total annual energy use (which approximates 1.8 million MWh per year)
and approximately 1.6 times the size of SCP’s annual sales volume.
Table 13: SVCCE – Electric Energy Overview
Current Service
Provider Customer Accounts Customer Accounts
(% of Total) Energy Use (MWh) Energy Use
(% of Total)
PG&E (“Bundled”
electric accounts)
243,440 99.7% 3,971,985 83%
Direct Access electric
accounts
765 0.3% 799,268 17%
Total – SVCCE Study
Partners
244,205 100.0% 4,771,253 100.0%
Figure 11 shows how potential electric customers are distributed throughout communities of the CCE Study
Partners: the largest customer populations within the potential CCE jurisdiction include the City of Sunnyvale,
the City of Mountain View, unincorporated areas of Santa Clara County, the City of Cupertino and the City of
Campbell.
26 Consideration of Senate Bill 286 (Hertzberg), which would have expanded eligibility of direct access service within
California, subject to the provision of increased levels of renewable energy supply, was recently suspended by the California
legislature and is now a two-year bill. In consideration of this suspension, the participatory cap on direct access service
remains capped/fixed at current levels, precluding new customer accounts from enrolling in such service options.
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Figure 11: Geographic Distribution of Customers
Figure 12 shows the distribution of electric consumption by municipality. The geographic distribution of
energy consumption is somewhat different when compared to the service account data in Figure 11 above,
indicating disproportionately higher use in certain communities (as a result of differentiated account
composition, particularly higher concentrations of larger commercial and/or industrial account types, within
such jurisdictions).
Figure 12: Geographic Distribution of Electric Consumption
In deriving the load projections used for the Study, adjustments to the base forecast were made to remove
customers identified as taking service under direct access27 as it was assumed that direct access customers
would remain with their current electric service provider. Further adjustments were made to estimate customer
27 Direct access allows customers to choose to receive generation service from competitive electricity providers. Currently,
direct access service is not available to new customers within California. Proposed legislation may lead to the reopening of
this service option at some point in the future.
0%5%10%15%20%25%30%
Sunnyvale
Mountain View
Unincorporated Santa Clara
Cupertino
Campbell
Gilroy
Morgan Hill
Los Gatos
Los Altos
Saratoga
Los Altos Hills
Monte Sereno
0%5%10%15%20%25%30%35%40%
Sunnyvale
Mountain View
Unincorporated Santa Clara
Gilroy
Cupertino
Morgan Hill
Campbell
Los Gatos
Los Altos
Saratoga
Los Altos Hills
Monte Sereno
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opt-out rates during the statutory customer notification period when eligible customers would be offered CCE
service and provided with information enabling them to opt out of the program. PEA assumed a 15%
customer opt-out rate, which is generally consistent with the reported opt-out rates observed during recent
expansions of the MCE program, when evaluating each of SVCCE’s prospective supply scenarios. Sensitivities
using different opt-out rates are presented in Section 6.
Going forward, potential customers and energy consumption were projected to increase by 0.5% annually,
consistent with statewide projections and reflecting impacts from the significant emphasis being placed on
energy efficiency within the state. The most recent baseline sales forecast for the PG&E planning area
projects an average growth in energy consumption of 1.29% between 2013 and 2025.28 Adjusting the long-
term growth rate for estimates of incremental self-generation (e.g., rooftop photovoltaic systems) and
achievable energy efficiency yields an annual net energy consumption increase of approximately 0.3% for
the PG&E planning area.29 A slightly higher growth rate (0.5%) was used for the SVCCE sales forecast in
consideration of the above average growth expected for the SVCCE area.
Projected Customer Mix and Energy Consumption
The projections for enrolled customers (excluding direct access customers) and annual electricity consumption
for the major customer classifications are shown in Table 14. Hourly electricity consumption and peak demand
were estimated using hourly load profiles published by PG&E for each customer classification.
Table 14: Projected Accounts Totals and Energy Use for the SVCCE Customer Base
Customer Classification Customer
Accounts
Customer Accounts
(% of Total) Energy Use (MWh) Share of Energy
Use (%)
Residential 218,049 90% 1,336,200 34%
Small Commercial 19,120 8% 423,180 11%
Medium Commercial 2,527 1% 569,501 14%
Large Commercial 1,166 <1% 780,723 20%
Industrial 43 <1% 771,462 19%
Ag and Pumping 944 <1% 62,238 2%
Street Lighting 1,588 1% 20,619 1%
TOTAL* 243,437 100.0% 3,963,923** 100%
Peak Demand 660 MW (July)
*Numbers may not add due to rounding.
**These totals exclude accounts that currently receive generation service under direct access arrangements. Also excluded are a small number of
commercial customers receiving bundled service under a standby rate option, under which customers generate their own electricity and utilize the
grid primarily for backup purposes. It is assumed that SVCCE’s initial schedule of available rate options may not accommodate such customers as
the usage profile is sporadic and relatively costly to serve. As a result, the account totals and annual energy consumption statistics reflected in the
“Total” line item are slightly less than the overall account totals and energy usage reported at the beginning of Section 3.
The hourly load forecast indicates a peak demand of approximately 660 MW (occurring during the month of
July), a minimum demand of approximately 300 MW (occurring during the month of March), and an average
demand of about 450 MW. The minimum demand establishes the requirement for baseload energy (constant
production level), while the difference between the peak demand and the minimum demand would be met by
peaking and dispatchable, load following resources.
28 Kavalec, Chris, 2015. California Energy Demand Updated Forecast, 2015-2025. California Energy Commission, Electricity
Supply Analysis Division. Publication Number: CEC-2002014-009-CMF, Table 6.
29 Ibid., Table 26
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Figure 13 shows the hourly load projections for the CCE program in Year 1 of program operations.
Figure 13: Hourly Electric Load Profile for the CCE Study Partners
Renewable Energy Portfolio Requirements
Current law requires that specified percentages of annual retail electricity sales be supplied from qualified
renewable energy resources. Senate Bill X1 2 (April, 2011) established a 33% Renewables Portfolio
Standard by 2020 with certain interim procurement targets applying in each of three “Compliance Periods”:
Compliance Period 1 began on January 1, 2011 and concluded on December 31, 2013 (a three-year
period); Compliance Period 2 began on January 1, 2014 and will continue through December 31, 2016 (a
three-year period; the current compliance period); and Compliance Period 3 (a four-year period), which will
commence on January 1, 2017 and conclude on December 31, 2020.
-
100,000
200,000
300,000
400,000
500,000
600,000
700,000
KW
Annual Hourly Load Profile
600,000 - 700,000
500,000 - 600,000
400,000 - 500,000
300,000 - 400,000
200,000 - 300,000
100,000 - 200,000
- - 100,000
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SBX1 2 also specified additional requirements for the types of renewable energy products that may be used
to demonstrate compliance with California’s RPS. According to the currently effective RPS program, there are
three Portfolio Content Categories (“PCCs” or “Buckets”) that have been defined in consideration of the
unique product attributes associated with typical renewable energy products.
PCC1, or Bucket 1, renewable products are produced by RPS-certified renewable energy generators
located within the state or by out-of-state generators that can meet strict scheduling requirements,
ensuring deliverability to California. For purposes of demonstrating RPS compliance, there are no
limitations with regard to the use of PCC1 products.
PCC2, or Bucket 2, renewable products are generally “firmed/shaped” transactions through which the
energy produced by an RPS-certified renewable energy generator is not necessarily delivered to
California, but an equivalent quantity of energy from a different, non-renewable generating resource
is delivered to California and “bundled” (or associated via an electronic transaction tracking system)
with the renewable attribute produced by the aforementioned RPS-certified renewable generator.
As noted, PCC2 products rely on electronic transaction tracking systems to substantiate the delivery of
specified quantities of RPS-eligible renewable energy.
PCC3, or Bucket 3, renewable products refer to unbundled renewable energy certificates, which are
sold separately from the associated electric energy (with no physical energy delivery obligations
imposed on the seller of such products).
Under RPS rules, limitations apply with regard to the use of PCC2 and PCC3 products. A more detailed
description of the renewable product procurement specifications applicable under the currently effective RPS
program are described in Table 15.
Table 15: Renewable Energy Procurement Requirements of California’s RPS Program
Compliance
Period
Calendar
Year
Overall
Procurement Target
(% of Total Retail
Sales)
PCC1
Procurement
(% of Total RPS
Procurement)
PCC2
Procurement
(% of Total RPS
Procurement)*
PCC3
Procurement
(% of Total RPS
Procurement)
CP 1 2011 20.0% ≥50.0% ≤50.0% ≤25.0%
CP 1 2012 20.0% ≥50.0% ≤50.0% ≤25.0%
CP 1 2013 20.0% ≥50.0% ≤50.0% ≤25.0%
CP 2 2014 21.7% ≥65.0% ≤35.0% ≤15.0%
CP 2 2015 23.3% ≥65.0% ≤35.0% ≤15.0%
CP 2 2016 25.0% ≥65.0% ≤35.0% ≤15.0%
CP 3 2017 27.0% ≥75.0% ≤25.0% ≤10.0%
CP 3 2018 29.0% ≥75.0% ≤25.0% ≤10.0%
CP 3 2019 31.0% ≥75.0% ≤25.0% ≤10.0%
CP 3 2020 33.0% ≥75.0% ≤25.0% ≤10.0%
*Note that PCC2 products may be used in place of PCC3 products.
Beyond the 2020 calendar year, California’s RPS procurement target was recently increased to 50% by
2030 – Governor Brown signed SB 350 (De Leon and Leno), the Clean Energy and Pollution Reduction Act of
2015, on October 7, 2015; SB 350 increases California’s RPS procurement target to 50% by 2030 amongst
other clean-energy initiatives. Many details related to SB 350 implementation will be developed over time
with oversight by designated regulatory agencies. However, it is reasonable to assume that interim annual
renewable energy procurement targets will be imposed on CCEs and other retail electricity sellers to facilitate
progress towards the 50% RPS; PEA also expects that additional detail regarding renewable energy product
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eligibility, including any restrictions and/or requirements regarding the use of such products, will also become
clearer during upcoming implementation efforts.
For purposes of this Study, PEA assumed straight-line progress when moving from the 33% RPS mandate in
2020 to the 50% RPS mandate in 2030, or 1.7% annual increases in California’s renewable energy
procurement target during the ten-year transition period. With respect to the applicability of various
renewable energy products that may be eligible under the prospective 50% RPS, PEA assumed a similar
product mix to that which will be allowed under the current RPS program in calendar year 2020: minimum
75% PCC1 content; maximum 10% PCC3 content. Again, final details related to the implementation of SB
350 will not be certain until implementation of this legislation commences in coordination with assigned
regulatory agencies. With regard to any voluntary (above-RPS) renewable energy procurement activities,
PEA has assumed that the CCE program would have discretion in how it meets such voluntary, internally
imposed targets reflected in the prospective planning scenarios. Table 16 illustrates PEA’s assumed RPS
procurement rules as California transitions to a 50% RPS by 2030.
Table 16: Projected Renewable Energy Procurement Requirements Following SB350 Implementation
Compliance
Period
Calendar
Year
Overall
Procurement Target
(% of Total Retail
Sales)
PCC1
Procurement
(% of Total RPS
Procurement)
PCC2*
Procurement
(% of Total RPS
Procurement)*
PCC3
Procurement
(% of Total RPS
Procurement)
TBD 2021 34.7% ≥75.0% ≤25.0% ≤10.0%
TBD 2022 36.4% ≥75.0% ≤25.0% ≤10.0%
TBD 2023 38.1% ≥75.0% ≤25.0% ≤10.0%
TBD 2024 39.8% ≥75.0% ≤25.0% ≤10.0%
TBD 2025 41.5% ≥75.0% ≤25.0% ≤10.0%
TBD 2026 43.2% ≥75.0% ≤25.0% ≤10.0%
TBD 2027 44.9% ≥75.0% ≤25.0% ≤10.0%
TBD 2028 46.6% ≥75.0% ≤25.0% ≤10.0%
TBD 2029 48.3% ≥75.0% ≤25.0% ≤10.0%
TBD 2030 50.0% ≥75.0% ≤25.0% ≤10.0%
*Note that PCC2 products may be used in place of PCC3 products.
Capacity Requirements
The CCE program would be required to demonstrate it has sufficient physical generating capacity to meet its
projected peak demand (660 MW) plus a 15% planning reserve margin, in accordance with resource
adequacy regulations administered by the CPUC and the CEC. A specified portion of generating capacity
must be located within certain local reliability areas and the remaining capacity requirement can be met with
generating plants anywhere within the CAISO system. Presently, there are two local reliability areas (as
defined in the CPUC’s annual Resource Adequacy Guide) that would apply to the CCE program: the “Greater
Bay Area” and the “Other PG&E Areas.” Additionally, the CPUC and CAISO impose a flexible capacity
requirement, which must be satisfied by all California load serving entities, including CCEs, to ensure that
certain quantities of reserve capacity are capable of increasing generation levels within specified time
periods (to promote system reliability when the production from certain grid-connected generators quickly
changes as is becoming increasingly common as a result of California’s buildout of intermittent renewable
energy resources).
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Based on PEA’s experience in managing resource adequacy portfolios and compliance activities, the following
resource adequacy capacity requirements were assumed to apply to SVCCE’s CCE program to meet the
requirements identified above. Such resource adequacy capacity requirements are identified in Table 17.
Table 17: SVCCE’s Projected Resource Adequacy Capacity Requirements
Capacity Type Percentage of Peak Demand
CAISO System 75%
Greater Bay Area 14%
Other PG&E Areas 26%
Total 115%
Accordingly, the total resource adequacy requirement for SVCCE’s first year of full operations would be
approximately 631 MW per month, with approximately 75 MW of the total procured from the Greater Bay
Area region, 145 MW procured from any other local reliability area in the PG&E service area, and 410 MW
procured from anywhere within the CAISO northern region (NP15). Requisite resource adequacy products
are typically procured/secured through one or more of the following arrangements: 1) short- to medium-term
contract arrangements with the owners or controllers of qualifying generating capacity; 2) capacity attributes
conferred through long-term power purchase arrangements with specified generators – such contracts
typically provide the buyer with both energy and capacity products from one or more specific generating
resources identified in the purchase agreement; or 3) direct ownership of generating facilities, which may be
eligible to provide requisite resource adequacy capacity.
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SECTION 4: COST OF SERVICE ELEMENTS
This section summarizes the different types of costs that would be incurred by the CCE program in providing
electric service to its customers. For each supply scenario, a detailed pro forma was developed that
delineates the applicable cost of service elements. These pro forma are shown in Appendix A.
Electricity Purchases
The CCE program would be financially responsible for supplying the net electric demand of all enrolled
customers, and it would be able to source that supply from a variety of markets and/or through the
program’s own generation resources. Energy requirements are ultimately financially settled by the CAISO.
The CAISO plays a critical role in balancing supply and demand on a significant portion of California’s
electric grid and operates short-term markets for energy as well as real-time balancing services to cover
inevitable moment-to-moment fluctuations in electricity consumption (resulting from circumstances including but
not limited to weather, unexpected changes in customer energy use, unexpected variances in generator
operation, infrastructure outages and other situations). The CCE program would interact with the CAISO
through an intermediary known as a “Scheduling Coordinator”, periodically reporting usage data for its
customers and settling with the CAISO for any imbalances (i.e., instances in which the load forecast and/or the
planned generator operation differs from expectations, requiring the CAISO to balance any variances
through the operation of other system resources) or transactions in the CAISO markets.
Bilateral markets exist for longer term purchases, which allow hedging (i.e., contractual protection via
specified/fixed product pricing over a mutually agreed upon delivery term) against the fluctuations in CAISO
market prices. Longer term purchases can span many years, with the most active trading being for contracts
with terms of less than three years in duration. Contracts for new generation resources typically have contract
term lengths of twenty (20) years or more, allowing the project developer/owner to utilize the contract’s
expected revenue stream to support project financing.
Electric purchase costs were estimated using the projected energy demand during the industry-defined peak
and off-peak time periods. Assumed renewable energy contracts of the CCE program, as reflected in the
previously described indicative long-term contract portfolio, were subtracted from SVCCE’s expected peak
and off-peak energy demands, resulting in a residual energy requirements, or “net short”, which was assumed
to be met with short and mid-term contract purchases of system energy (produced by conventional generating
technologies; within California, the majority of system energy is produced by generators using natural gas as
a primary fuel source).
Renewable Energy Purchases
Renewable energy purchases may take two forms: 1) physical electric energy bundled with associated
renewable/environmental attributes; or 2) unbundled renewable/environmental attributes, which are sold
separately from the physical energy commodity. As described in Section 2, unbundled RECs were not
incorporated in any of the supply scenarios addressed in this Study; only bundled renewable energy
resources, which were assumed to meet the product delivery specifications associated with the PCC1 and
PCC2 product designations were incorporated in the indicative SVCCE supply portfolios.
Purchases of renewable energy from new resources are typically made under bundled, long-term contract
arrangements of 20 years or more. Shorter term purchases are common for existing renewable resources and
for unbundled renewable energy certificates.
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Renewable energy currently sells for a premium relative to the cost of conventional power. However, when
compared to the cost of new, natural gas-fueled generation, renewable resources tend to have lower
levelized costs.30
Renewable energy purchase costs were estimated using predominantly long-term contracts for new renewable
energy projects as specified in the indicative long-term contract portfolio. Short-term market purchases of
bundled renewable energy were assumed to fulfill SVCCE’s remaining renewable energy needs.
With regard to the term renewable energy certificates, or “RECs”, it is important to understand that a REC is
the only mechanism by which ownership of renewable energy can be demonstrated/substantiated. One REC
is created for every whole MWh of metered electricity produced by a registered renewable generating
facility. Within the Western United States, a tracking system known as the Western Renewable Energy
Generation Information System (“WREGIS”) has been developed to facilitate the management of RECs,
providing a platform through which RECs can be transferred between buyers and sellers of renewable energy
products and also “retired” (meaning, removed from the marketplace) for purposes of demonstrating
legal/regulatory compliance or achievement of certain voluntary procurement objectives. All renewable
energy production is substantiated via the creation of a REC, which occurs following WREGIS’ verification of
metered energy production by a registered renewable generating resource. Use of the WREGIS system for
purposes of REC accounting serves to minimize concerns regarding double-counting during compliance
demonstration and public reporting – in the event that a renewable energy buyer does not possess a REC, it
cannot make claims with regard to the associated environmental benefits.
Again, some RECs are bundled with the associated electric energy; other RECs are sold apart from the electric
commodity – such RECs are appropriately referred to as “unbundled RECs”. The transaction documentation
associated with each renewable energy purchase should outline applicable product specifications, including
whether or not RECs are being sold with or apart from the electric commodity. In selecting its renewable
energy product mix, the CCE program should be aware that California law permits the use of a limited
quantity of unbundled RECs, or PCC3 product volumes, for purposes of demonstrating RPS compliance –
applicable limitations were previously described in Section 3. Such products currently represent lower-cost
options when compared to PCC1 and PCC2 products due to the administrative simplicity associated with such
transactions.
In recent years, there has been robust philosophical debate regarding the advantages and pitfalls of
unbundled REC use, particularly the environmental benefits associated with such products. Significant research
and documentation has been prepared regarding this topic, and SVCCE is encouraged to review such
information prior to engaging in unbundled REC transactions. Organizations including the Center for
Resources Solutions (the program administrator for the Green-e Energy program), the United States
Environmental Protection Agency, the United States Federal Trade Commission and The Climate Registry,
amongst others, have all completed research and/or issued positions regarding the use of unbundled RECs.
Furthermore, Assembly Bill 1110 (Ting), which was introduced to the California legislature on February 27,
2015 but is now a two-year bill, was intended to promote the inclusion of GHG emissions intensity reporting
by retail electricity suppliers (in annual Power Content Label communications). If AB 1110 moves forward
next year, it could impose a retail-level emissions calculation methodology that may eliminate all GHG
emissions benefits associated with unbundled RECs. In consideration of the CCE Study Partners’ preliminary
planning decision to exclude the use of unbundled RECs from all prospective supply scenarios, the potential
change in GHG reporting conventions contemplated under AB 1110 would not present any issues for SVCCE.
30 See for example, Table 62, Estimated Cost of New Renewable and Fossil Generation in California, California Energy
Commission, March 2015.
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However, if SVCCE chooses to reconsider the use of unbundled RECs at some point in the future, it should be
aware that such a practice may result in the reporting of higher than anticipated portfolio emission levels. As
previously discussed and in light of the perceived risks and general controversy associated with the use of
unbundled RECs, the CCE Study Partners advised PEA to exclude Bucket 3 products from each of the
prospective supply scenarios.
Electric Generation
Generation projects developed or acquired by the CCE program could also supplement energy purchases.
Generation costs would include development costs, capital costs for land, plant and equipment, operations
and maintenance costs, and, if applicable, fuel costs. Capital costs for publicly owned utilities such as a CCE
are typically financed with long-term debt, and the annual debt service would be an element of annual CCE
program costs. For purposes of this Study, PEA’s analysis did not contemplate the utilization of CCE-
owned/developed generating resources during the ten-year study period for reasons previously described.
Transmission and Grid Services
The CAISO charges market participants, including CCEs (via the CCE’s selected scheduling coordinator) for a
number of transmission and grid management services that it performs. These include costs of managing
transmission congestion, acquiring operating reserves and other “ancillary services”, and conducting CAISO
markets and other grid operations. The CAISO charges are both directly related to SVCCE’s operations, but
there are other grid charges that are shared across all load serving entities on a pro rata basis. These costs
would be assessed to the Scheduling Coordinator for the CCE program, and are assumed to be directly
passed through to the CCE program with no markup.
Start-Up Costs
Start-up costs are estimated to be nearly $2.9 million, which would provide necessary program funding
during the approximate twelve-month period immediately preceding service commencement to SVCCE
customers. Start-up costs include SVCCE staffing and requisite professional services, security deposits, the CCE
bond/financial security requirement, communications and customer notices, data management, and other
activities that must occur before the program begins providing electricity to its customers. These costs would be
recovered through SVCCE rates after service commences. A breakdown of estimated start-up costs is shown in
Table 18.
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Table 18: Estimated SVCCE Program Start-Up Costs
Cost Item Amount
Internal Staff $730,000
Technical Consulting and Legal Services $620,000
Marketing and Communications $280,000
Customer Noticing and Mailers $120,000
Security Deposits $40,000
Miscellaneous Administrative and General $95,000
CCE Bond $100,000
Debt Service $720,000
Other Pre-launch Activities $180,000
Total $2,885,000
SVCCE start-up cost estimates are based on expenses incurred during the pre-launch activities of California’s
operating CCE programs. More specifically, PEA developed a start-up cost profile in consideration of the
actual experiences of California’s operating CCE programs, then scaled SVCCE start-up cost estimates based
on relative size (electric energy requirements) and customer composition when compared to the representative
start-up cost profile. A detailed description of each cost item is provided below.
Internal Staffing: As an independently operating JPA, it is assumed that the SVCCE program will begin to
hire its own staff (on an interim or full-time basis, depending on specific job responsibilities) twelve months
prior to service commencement.
Technical Consulting and Legal Services: Includes services provided by experienced firms and/or
individuals to support the following pre-launch activities: contract negotiations (with data management
providers and energy suppliers), regulatory and compliance reporting, load forecasting, rate design and
ratesetting, customer rate analysis, joint mailer content development, pro forma and budget development,
and other portfolio management services. Costs also include discussions, technical analysis, and negotiations
(with banking and financial institutions) related to securing financing for Program operations. This line item
generally addresses related costs that will be incurred during the twelve-month period immediately preceding
SVCCE launch.
Marketing and Communications: Includes costs specific to marketing, communications and customer outreach,
which are assumed to be outsourced services for purposes of this Study. Additional costs include the design
and printing of marketing materials, advertising across various media, and sponsorship of community events.
Customer Noticing and Mailers: Includes costs associated with the first two customer mailers (printing and
postage), which will be sent to prospective customers prior to service commencement – these notices are also
commonly referred to as “opt-out notices.” Estimates are based on costs incurred by existing CCE programs.
Security Deposits: Includes amounts required to satisfy the PG&E security deposit, which equates to the
monthly average PG&E service fee to be incurred by SVCCE during its first year of operation. The security
deposit is typically posted around the same time as the CCE Bond (which will be posted with the CPUC).
Miscellaneous Administrative and General: Includes additional overhead during the twelve-month period
immediately preceding service commencement. Some of these costs include travel, office supplies, and rent
for office space.
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CCE Bond: An amount equal to $100,000, which SVCCE would be required to post with the CPUC prior to
launching the Program. For purposes of this Study, it is assumed that the CCE Bond is posted upon certification
of the Implementation Plan.
Debt Service: Includes interest and principal payments associated with initial program financing. Such
payment obligations are expected to commence four months prior to service commencement. Depending on
SVCEE’s final credit structure, SVCCE could potentially negotiate terms that are more closely aligned with the
anticipated timing of rate revenue receipt. SVCCE’s “bridge-financing”, which is required to ensure that the
Program has adequate working capital at the time of launch and during the months immediately thereafter, is
the basis for assumed debt service payments.
Other Pre-Launch Activities: Includes costs related to Implementation Plan development, product and
portfolio design (i.e., the compilation and description of default and voluntary retail service options as well as
requisite portfolio accounting activities to ensure that all customer commitments are satisfactorily addressed),
and Request for Proposal development and administration (to secure requisite data manager services, energy
products and scheduling coordinator services). Costs would be incurred by SVCCE during the twelve-month
period immediately preceding service commencement.
Financing Costs
SVCCE would need access to capital for the primary purposes of covering anticipated start-up costs and
working capital requirements as well as any other project financing needs that may arise. Working capital
requirements are estimated at $9 million (with related debt service reflected in Table 18 above), which would
cover cash flow needs, primarily arising from the timing lag between power purchase payment deadlines and
the receipt of customer revenues. The noted $9 million in working capital requirements is additive to the $2.9
million in start-up costs (discussed above in the “Start-Up Costs” sub-section). Typical invoicing timelines for
wholesale power purchase contracts require payment (for the prior month’s energy deliveries) by the 20th of
each month. Customer payments (revenues) are typically received within sixty to ninety days following
electricity delivery. The timing difference between cash outflows and inflows represents SVCCE’s working
capital requirement. The possibility exists to negotiate payment timelines with power suppliers in order to
reduce SVCCE’s initial working capital requirement. For example, both SCP and LCE have negotiated an
additional 30 days in the supplier payment timeline, which significantly reduces each organization’s working
capital need.
Billing, Metering and Data Management
PG&E provides billing and metering services for all CCE programs and charges the CCE for such services in
accordance with applicable tariffs, which are regulated by the CPUC. PG&E posts the meter data to a data
server that the CCE program would be able to access for its power accounting and settlements. PG&E uses
systems to exchange billing, payment, and other customer data electronically with competitive retail electric
providers such as CCEs. While PG&E issues customer bills and processes customer payments, the CCE
program will have a large amount of data to manage and must be able to exchange data with PG&E using
automated processes. PEA included costs for third party data management as well as PG&E charges for
billing and metering in this cost of service category.
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Staff and Other Operating Costs
Internal staffing and/or contractors would be required to manage SVCCE’s day-to-day operations. These
activities include program management, financial administration, resource planning, marketing and
communications, regulatory compliance and advocacy, and other general administration. Such costs were
estimated for SVCCE based on a review of the publicly available budgets adopted by the currently
operating CCE programs: Marin Clean Energy, Sonoma Clean Power, and Lancaster Choice Energy.
Additional costs were included for administration of certain demand side programs anticipated to be offered
by SVCCE. These programs may include customer self-generation (net energy metering) program incentives,
electric vehicle charging programs, energy efficiency and demand response programs. Included in the pro
forma projections for this cost element is an assumed $1,275,000 annual budget to support the administration
of such programs, which is assumed to include the funding of various customer incentives that may be offered
by SVCCE. SVCCE may also qualify for additional funding for administration of energy efficiency programs
through application to the CPUC.
Uncollectible Accounts
CCE rates must account for the small fraction of customers who do not pay their electric bill. PG&E attempts
to collect the CCE’s charges, but some accounts must be written off as uncollectible. An allowance for
uncollectible accounts has been included as a program cost element.
Program Reserves
A reasonable revenue surplus was factored in to estimated SVCCE rates to fund a reserve account that would
be used for contingencies or as a rate stabilization tool. Financing also requires generation of net revenues
that accumulate as reserves, as lenders typically require maintenance of debt service coverage ratios that
would necessitate setting rates to yield revenues in excess of program costs.
Bonding and Security Requirements
SVCCE would be required to provide a security deposit to PG&E and post a bond or other form of financial
security with the CPUC as part of its registration process. The security deposit covers approximately one
month of PG&E charges for billing and metering services. The CCE bond or financial security requirement,
which is posted with the CPUC, is intended to cover the potential reentry costs if customers were to be
involuntarily returned to PG&E.
The currently effective financial security requirement is $100,000, but PG&E and other investor owned utilities
have advocated changes to the methodology that could, under certain market conditions, result in extremely
large financial security requirements. PEA’s estimate of the CCE Bond amount reflects the currently applicable
specification ($100,000). However, the CCE program should actively monitor applicable regulatory
proceedings, which may result in changes to this bond amount. Risks associated with such changes are
discussed in additional detail within Section 7 of this Study.
PG&E Surcharges
SVCCE customers will pay the CCE’s rates for generation services, PG&E’s rates for non-generation services
(transmission, distribution, public purpose, etc.), and two surcharges that are currently included in PG&E’s
generation rates: the Franchise Fee Surcharge and the Power Charge Indifference Adjustment (“PCIA”). These
surcharges are not program costs per se, but they do impact how a customer’s bill will compare between
PG&E bundled service and CCE service.
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The franchise fee surcharge is a minor charge that ensures PG&E collects the same amount of franchise fee
revenues whether a customer takes generation service from a CCE or from PG&E. The PCIA is a substantial
charge that is intended to ensure that generation costs incurred by PG&E before a customer transitions to CCE
service are not shifted to remaining PG&E bundled service customers (following a customer’s departure from
PG&E to CCE service). For purposes of this Study, PEA’s assumed surcharges reflect the most recent advice
provided by PG&E and assumed changes to the PG&E supply portfolio over time.
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SECTION 5: COST AND BENEFITS ANALYSIS
This section contains a quantitative description of the estimated costs and benefits for each representative
supply scenario. Each scenario was evaluated using the three criteria described in Section 2. Ratepayer costs
and benefits are evaluated on the basis of the total electric rates customers would pay under CCE service as
compared to PG&E bundled service. Total electric rates include the rates charged by the CCE program plus
PG&E’s delivery charges and other surcharges. Environmental benefits are evaluated on the basis of
reductions in GHG (CO2) emissions relative to the reference case. Local economic benefits are evaluated on
the basis of jobs and economic activity created by the CCE program’s investments in local generation
resources.
When assessing the comparative environmental impacts associated with each of SVCCE’s prospective supply
scenarios, it is important to consider the potential changes that could result from PG&E’s reduced or
discontinued use of nuclear electricity produced by the Diablo Canyon Power Plant (“DCPP”). DCPP currently
produces approximately 18,000 GWh, or more than 20% of PG&E’s total power content, per year, but
licenses for the facility’s two reactor units expire in 2024 and 2025, respectively. At this point in time, there is
uncertainty regarding PG&E’s ability to successfully relicense these units under the current configuration, which
utilizes once-through cooling as part of facility operations. Environmental concerns regarding the use of once-
through cooling may present relicensing challenges for PG&E, which could result in temporary or permanent
discontinued operation of DCPP. Under this scenario, which falls towards the outer years of the study period,
SVCCE’s actual GHG emissions impact would dramatically improve under each of the prospective supply
scenarios. It is also noteworthy, that discontinued DCPP operation (without the addition of equivalent
generating capacity within the region) may also impose upward pressure on market energy prices and
resource adequacy products. PEA recommends that the CCE Study Partners continue to monitor the relicensing
status of DCPP as expiration of the existing licenses approaches.
As previously discussed (in Section 2), it is important to keep in mind the planned phase-in strategy for the
prospective SVCCE customer base, which is expected to occur over a three-year period. The projected
operating results reflected in the Study demonstrate the impacts of a phase-in strategy that would enroll
customers in the following manner: 1) one-third of prospective SVCCE customers would be enrolled during the
first month of service, drawing from a broad, representative cross section of the entire SVCCE customer base;
2) another third of the original customer population (i.e., half of the remaining customer population which had
yet to be enrolled) would be transitioned to CCE service during the thirteenth month of operation, reflecting
similar characteristics when compared with the first phase; and 3) all remaining customers not previously
enrolled would be transitioned to CCE service during the twenty fifth month of program operations.
Scenario 1 Study Results
Ratepayer Costs
The primary objective of Scenario 1 is to match the GHG emissions intensity of PG&E’s projected supply
portfolio while also exceeding the incumbent utility’s proportionate renewable energy supply without the use
of unbundled RECs. Consistent with PEA’s expectations, projected SVCCE customer rates in Scenario 1 are
lower than similar rate projections for PG&E throughout the ten-year study period, with annual comparative
benefits ranging from 3% to 5%. Levelized rates over the study period are projected to be 4% lower than
projected PG&E rates. For a typical household using 510 kWh per month, a 4% rate difference would result
in a cost reduction of approximately $5.09 per month in Year 1 of program operations.
Projected average rates for the SVCCE customer base are shown in Figure 14 and Table 19, comparing total
ratepayer impacts under the PG&E bundled service and CCE service options.
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Figure 14: Scenario 1 Annual Ratepayer Costs
Table 19: Scenario 1 - Annual Total Delivered Rate Comparison
Year
PG&E
Total
(₵/kWh)
SVCCE
Total
(₵/kWh)
Percent
Difference
Levelized 22.27 21.49 -4%
1 19.51 18.64 -4%
2 19.94 19.08 -4%
3 20.59 19.48 -5%
4 21.29 20.35 -4%
5 21.90 21.19 -3%
6 22.42 21.80 -3%
7 23.14 22.49 -3%
8 23.78 23.14 -3%
9 24.49 23.84 -3%
10 25.19 24.47 -3%
14.0
16.0
18.0
20.0
22.0
24.0
26.0
1 2 3 4 5 6 7 8 9 10
Ce
n
t
s
P
e
r
K
W
h
Year
AVERAGE TOTAL COST COMPARISON
SVCCE Service
PG&E Service
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GHG Impacts
Consistent with the primary Scenario 1 planning objective, SVCCE’s anticipated GHG emissions are equivalent
to projected GHG emissions of the PG&E supply portfolio. A combination of renewable and other GHG-free
energy purchases is assumed to achieve this environmental outcome. The following figures and tables provide
additional detail regarding the respective GHG emissions profile associated with the assumed SVCCE and
PG&E supply portfolios.
Figure 15: Scenario 1 – Annual GHG Emissions Comparison
Table 20: Scenario 1 - Annual GHG Emissions Factor Comparison (Metric Tons CO2/MWh)
Year PG&E SVCCE
1 0.158 0.158
2 0.149 0.149
3 0.139 0.139
4 0.131 0.131
5 0.127 0.127
6 0.123 0.123
7 0.120 0.120
8 0.116 0.116
9 0.112 0.112
10 0.109 0.109
-
100,000
200,000
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600,000
1 2 3 4 5 6 7 8 9 10
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Year
ATTRIBUTED PORTFOLIO EMISSIONS
PG&E SVCCE
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Figure 16: Scenario 1 – Annual Renewable Energy Content Comparison
Table 21: Scenario 1 - Annual Renewable Energy Portfolio Content
Year PG&E SVCCE
1 27% 36%
2 27% 36%
3 30% 36%
4 33% 38%
5 35% 39%
6 36% 41%
7 38% 43%
8 40% 45%
9 42% 47%
10 43% 49%
0%
10%
20%
30%
40%
50%
60%
1 2 3 4 5 6 7 8 9 10
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RENEWABLE ENERGY CONTENT
SVCCE RENEWABLE PORTFOLIO PG&E RENEWABLE PORTFOLIO
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Page 56 Section 5: Cost and Benefits Analysis
Scenario 2 Study Results
Ratepayer Costs
The primary objective of Scenario 2 is to increase the use of renewable energy resources while also
promoting overall annual GHG emissions reductions of 20% relative to the incumbent utility. For purposes of
the Study, this objective is achieved through the inclusion of renewable energy purchases that significantly
exceed applicable compliance mandates (doing so without the use of unbundled RECs) as well as additional
GHG-free energy purchases, which would be produced by non-RPS-eligible hydroelectric generators located
within California and/or the Pacific Northwest. Under Scenario 2, projected CCE customer rates are initially
lower than similar rate projections for PG&E and maintain that general relationship throughout the study
period – the relationship between SVCCE and PG&E rates demonstrates marginal customer savings ranging
from 1% to 4%. Levelized rates over the study period are projected to be 2% lower than projected PG&E
rates. However, in consideration of typical market volatility within the electric power sector and eminent
PG&E rate volatility, these results should be reasonably interpreted as reflecting only minimal rate savings
throughout the study period. For a typical household using 510 kWh per month, a 2% rate difference would
result in a cost reduction of approximately $2.46 per month.
Projected average rates for the SVCCE customer base are shown in Figure 17 and Table 22, comparing total
ratepayer impacts under the PG&E bundled service and CCE service options.
Figure 17: Scenario 2 Annual Ratepayer Costs
14.0
16.0
18.0
20.0
22.0
24.0
26.0
1 2 3 4 5 6 7 8 9 10
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W
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Year
AVERAGE TOTAL COST COMPARISON
SVCCE Service
PG&E Service
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Section 5: Cost and Benefits Analysis Page 57
Table 22: Scenario 2 - Annual Total Delivered Rate Comparison
Year PG&E
Total
(₵/kWh)
SVCCE
Total
(₵/kWh)
Percent
Difference
Levelized 22.27 21.80 -2%
1 19.51 18.91 -3%
2 19.94 19.36 -3%
3 20.59 19.77 -4%
4 21.29 20.62 -3%
5 21.90 21.47 -2%
6 22.42 22.11 -1%
7 23.14 22.82 -1%
8 23.78 23.49 -1%
9 24.49 24.21 -1%
10 25.19 24.86 -1%
GHG Impacts
As a result of the significant proportion of GHG-free resources that were incorporated in Scenario 2, the CCE
program is able to demonstrate the desired GHG emissions reduction target of 20% when compared to
PG&E’s projected emissions profile. The following figures and tables provide additional detail regarding the
respective GHG emissions profile associated with the assumed SVCCE and PG&E supply portfolios.
Figure 18: Scenario 2 – Annual GHG Emissions Comparison
-
100,000
200,000
300,000
400,000
500,000
600,000
1 2 3 4 5 6 7 8 9 10
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Year
ATTRIBUTED PORTFOLIO EMISSIONS
PG&E SVCCE
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Page 58 Section 5: Cost and Benefits Analysis
Table 23: Scenario 2 - Annual GHG Emissions Factor Comparison (Metric Tons CO2/MWh)
Year PG&E SVCCE
1 0.158 0.126
2 0.149 0.119
3 0.139 0.111
4 0.131 0.105
5 0.127 0.102
6 0.123 0.099
7 0.120 0.096
8 0.116 0.093
9 0.112 0.090
10 0.109 0.087
Figure 19: Scenario 2 – Annual Renewable Energy Content Comparison
0%
10%
20%
30%
40%
50%
60%
70%
1 2 3 4 5 6 7 8 9 10
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Year
RENEWABLE ENERGY CONTENT
SVCCE RENEWABLE PORTFOLIO PG&E RENEWABLE PORTFOLIO
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Section 5: Cost and Benefits Analysis Page 59
Table 24: Scenario 2 - Annual Renewable Energy Portfolio Content
Year PG&E SVCCE
1 27% 51%
2 27% 51%
3 30% 51%
4 33% 51%
5 35% 53%
6 36% 56%
7 38% 58%
8 40% 61%
9 42% 63%
10 43% 66%
Scenario 3 Study Results
Ratepayer Costs
It is generally appropriate to characterize Scenario 3 as an “optimized” supply scenario under which SVCCE’s
projected clean energy purchases are maximized subject to the imposition of a rate constraint, which required
that SVCCE’s rates remain equivalent to projected PG&E rates on a levelized basis throughout the Study
period. During individual years of the Study period, projected SVCCE and PG&E rates minimally differ within
a range demonstrating periods of moderate customer savings (2% savings in Year 3 of projected program
operations, for example) as well as negligible cost increases (which do not exceed 0.7% in any year of the
Study). Consistent with the imposed rate constraint, projected SVCCE customer rates remain generally
equivalent to similar rate projections for PG&E throughout the study period and typical residential customers
are expected to incur monthly charges that would be approximately $0.05 below similar PG&E charges on a
levelized basis.
Projected average rates for the SVCCE customer base are shown in Figure 20 and Table 25, comparing total
ratepayer impacts under the PG&E bundled service and CCE service options.
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Page 60 Section 5: Cost and Benefits Analysis
Figure 20: Scenario 3 Annual Ratepayer Costs
Table 25: Scenario 3 - Annual Total Delivered Rate Comparison
Year PG&E
Total
(₵/kWh)
CCE Total
(₵/kWh)
Percent
Difference
Levelized 22.27 22.26 0%
1 19.51 19.38 -1%
2 19.94 19.85 0%
3 20.59 20.27 -2%
4 21.29 21.15 -1%
5 21.90 21.97 0%
6 22.42 22.58 1%
7 23.14 23.26 1%
8 23.78 23.91 1%
9 24.49 24.59 0%
10 25.19 25.21 0%
GHG Impacts
Through the substantial use of renewable and other GHG-free energy resources, Scenario 3 suggests that the
CCE program could achieve substantial GHG emissions reductions when compared to PG&E’s projected
emissions profile. The following figures and tables provide additional detail regarding the respective GHG
emissions profile associated with the assumed SVCCE and PG&E supply portfolios.
14.0
16.0
18.0
20.0
22.0
24.0
26.0
1 2 3 4 5 6 7 8 9 10
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P
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K
W
h
Year
AVERAGE TOTAL COST COMPARISON
SVCCE Service
PG&E Service
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Section 5: Cost and Benefits Analysis Page 61
Figure 21: Scenario 3 – Annual GHG Emissions Comparison
Table 26: Scenario 3 - Annual GHG Emissions Factor Comparison (Metric Tons CO2/MWh)
Year PG&E SVCCE
1 0.158 0.064
2 0.149 0.055
3 0.139 0.045
4 0.131 0.037
5 0.127 0.033
6 0.123 0.029
7 0.120 0.025
8 0.116 0.022
9 0.112 0.018
10 0.109 0.015
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200,000
300,000
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500,000
600,000
1 2 3 4 5 6 7 8 9 10
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Year
ATTRIBUTED PORTFOLIO EMISSIONS
PG&E SVCCE
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Figure 22: Scenario 3 – Annual Renewable Energy Content Comparison
Table 27: Scenario 3 - Annual Renewable Energy Portfolio Content
Year PG&E SVCCE
1 27% 76%
2 27% 76%
3 30% 76%
4 33% 76%
5 35% 76%
6 36% 76%
7 38% 76%
8 40% 76%
9 42% 76%
10 43% 76%
0%
10%
20%
30%
40%
50%
60%
70%
80%
1 2 3 4 5 6 7 8 9 10
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RENEWABLE ENERGY CONTENT
SVCCE RENEWABLE PORTFOLIO PG&E RENEWABLE PORTFOLIO
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Section 6: Sensitivity Analyses Page 63
SECTION 6: SENSITIVITY ANALYSES
The economic analysis uses base case input assumptions for many variable factors that influence relative costs
of the CCE program. Sensitivity analyses were performed to examine the range of impacts that could result
from changes in the most significant variables (relative to base case values). The key variables examined are:
1) power and natural gas prices; 2) renewable energy prices; 3) low carbon energy prices; 4) PG&E rates;
5) PG&E surcharges; and 6) customer participation/opt-out rates. Additionally, a “small JPA” sensitivity case
was run reflective of minimal community participation in the SVCCE joint powers agency to test the viability of
a much smaller CCE program, and a “perfect storm” sensitivity was run to examine the cumulative impacts of
adverse changes to the key variables.
Power and Natural Gas Prices
Electric power prices in California are substantially influenced by natural gas prices, as natural gas-fired
generation is predominantly used as the marginal resource within the state’s system dispatch order. This fact
is consistent with how PEA developed the ten-year power price forecast in which a detailed natural gas
forecast was assembled and then converted to power prices using factors consistent with industry standards.
Changes in natural gas prices will also tend to change the power purchase costs of the CCE program. To the
extent that SVCCE’s selected supply portfolio excludes the use of conventional energy supply, the potential
impact related to price volatility within the natural gas market will be minimized. Such changes also influence
PG&E’s rates, but the relative cost impacts will differ depending upon the proportionate use of conventional
resources utilized by the CCE program relative to PG&E.
For the CCE program, the non-renewable portion of the supply portfolio will be influenced by changes in
natural gas and wholesale power prices. The PG&E resource mix includes resources that are influenced by
natural gas prices such as utility-owned natural gas fueled power plants, so-called “tolling” agreements with
independent generators, and certain other contracts that are priced based on an avoided cost formula. The
PG&E resource mix also includes energy sources that are not affected by natural gas prices, including
renewable resources as well as PG&E’s hydro-electric and nuclear assets.
Sensitivity to changes in natural gas and power prices were tested by varying the base case assumptions to
create high and low cases. The high case reflects a 50% increase in this input relative to the base case and
the low case reflects a 25% decrease relative to the base case.
Renewable Energy Costs
There can be wide variation in renewable energy costs due to locational factors (wind regime, solar insulation,
availability of feedstock for biomass and biogas facilities, etc.), transmission costs, technological changes,
federal tax policy, and other factors. In fact, the federal investment tax credit, or “ITC”, is expected to
decrease significantly for projects commencing operations on or after January 1, 2017 – the ITC is expected
to drop from 30% to 10%, based on PEA’s understanding, which could impose generally proportionate
increases to renewable energy pricing following such a change.
Sensitivity to renewable energy cost assumptions was tested by varying the base case costs for renewable
power purchase contracts and for the installed costs for renewable generation projects by 25% for the high
case and -25% for the low case. The variances were only applied to SVCCE’s cost structure and not PG&E’s
in order to test the impact of potential variation in site-specific renewable projects used by the CCE program.
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Page 64 Section 6: Sensitivity Analyses
Carbon-Free Energy Costs
Specified purchases from carbon-free resources or low carbon emissions portfolios generally yields a premium
relative to system energy purchases. In consideration of the potential for increased CCE demand for low
carbon content energy and the generally fixed supply of the large hydro-electric generation resource base
available to California consumers, only a high case was evaluated for this factor. The high carbon-free
energy cost premium scenario was evaluated at a 300% increase relative to the base case assumption.
PG&E Rates
The base case forecast for PG&E’s generation rates yields a projected average annual increase of
approximately 2.5%. The forecast relies on resource mix data provided by PG&E in its most recent long-term
procurement plan, and incorporates many of the same core market cost assumptions (natural gas prices,
power prices, GHG allowance prices, etc.) as used in the forecast of CCE program rates. Numerous factors
can cause variances in PG&E’s rates, and low and high cases were developed for this variable. One factor
that could have a significant increase on PG&E’s rates is the potential closure or rebuilding of DCPP, resulting
from regulations prohibiting the use of once-through cooling at the plant. A high case was created that
reflects an average annual generation rate increase of 5%. The low case assumes 1.5% annual rate
increases for PG&E. Figure 23 illustrates the base, high and low case forecasts of PG&E generation rates
and how these projections compare with historical trends.
Figure 23: PG&E System Average Generation Rates
6.0
6.9
7.5 7.4
8.0 8.1
6.7
7.1
7.9
8.6
9.7
9.29.2 9.4 9.6 9.9 10.3 10.5 10.7 11.1 11.4 11.7 12.0
9.2
9.7
10.1
10.6
11.2
11.7
12.3
12.9
13.6
14.3
15.0
9.2 9.3 9.5 9.6 9.8 9.9 10.0 10.2 10.4 10.5
5.0
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Reported Base Proj.High Proj.Low Proj.
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Section 6: Sensitivity Analyses Page 65
PG&E Surcharges
The PCIA and Franchise Fee surcharges directly impact SVCCE rate competitiveness, and the PCIA has been
volatile. In an August, 2015 filing to the CPUC, PG&E projected PCIA levels for 2016 that are
approximately 70% higher than current levels.31 In general terms, the PCIA is set on an annual basis in
consideration of a specified methodology that takes into consideration the difference in costs associated with
PG&E’s supply portfolio and a market benchmark – to the extent that costs associated with the PG&E supply
portfolio exceed the market benchmark, departing customers, including CCE customers, are subject to a PCIA
surcharge. The specific methodology that is employed when determining the PCIA is subject to PCIA oversight,
and PG&E must perform related PCIA calculations consistent with such methodology. Over time, PCIA charges
will change based on the relationship between PG&E’s power portfolio costs and current market pricing. In
concept, the PCIA should diminish (and eventually expire) over time, as PCIA charges are directly associated
with PG&E power contracts, all of which should have finite term lengths. Once such contracts expire, any
related PCIA impacts should fall to zero. However, because PG&E engages in ongoing contracting efforts,
PCIA charges may persist for 20 years or more (but should diminish over time). Figure 24 shows the projected
Franchise Fee Surcharge and PCIA applicable to residential customers as well as historical data illustrating the
volatility of these surcharges.
Figure 24: PG&E CCE Surcharges for Residential Customers (Cents Per KWh)
The base case PCIA projections begin with the higher 2016 PCIA charges reported by PG&E and remain
relatively flat over the forecast period. High and low cases were run at plus or minus 50% off of the base
case.
Opt-Out Rates
Sensitivity of ratepayer costs to customer participation in the CCE program was tested by varying the opt-out
rate from 25% in the high case to 5% in the low case. A higher opt-out rate would reduce sales volumes
relative to base case assumptions, and increase the share of fixed costs paid by each customer, while a lower
opt-out rate would have the opposite effect.
31 PG&E Advice Letter AL-4696-E.
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Page 66 Section 6: Sensitivity Analyses
Community Participation (Small JPA)
While the base case includes all municipalities as participants in the JPA, a sensitivity was run to examine the
impacts of a much smaller program being formed in the region. For purposes of this sensitivity, it was
assumed that 25% of the total potential customers are offered service in the CCE and that 15% of these
customers elect to opt-out. Adjustments were made to assumed staffing costs to reflect the smaller scale of
operations. The long term renewable contract portfolio was adjusted downward on a pro rata basis to
reflect the reduced energy requirements. The results of this sensitivity indicate that a viable program could be
operated with significantly less than 100% participation of the prospective communities. While not explicitly
modeled, a program serving only the four sponsoring partner agencies (representing 68% of the total
potential load) would have sufficient scale and be expected to have similar rates as presented in the base
case projections.
Perfect Storm
This sensitivity examines the cumulative effects of adverse changes to all of the key variables to present what
could be considered a worst case. The likelihood that all of these variables change in unison is remote; many
of the key variables are negatively correlated meaning that increases in one variable would normally be
associated with decreases in another. For example, increases in market prices for power should result in
decreases in the PG&E surcharges, but for purposes of this sensitivity it was assumed that the PG&E
surcharges would also increase. This sensitivity was constructed with the following assumptions: high natural
gas/power prices, high renewable energy and low carbon energy costs, high PG&E surcharges, high customer
opt-out rates, and low PG&E rates.
Sensitivity Results
The sensitivity analysis produced a range of levelized electric rates for the CCE program and PG&E as shown
in the Figure 25.32 When reviewing this figure, the base case outcomes associated with each scenario are
represented by the “arrowheads” that are positioned along each vertical line – to the extent each line
extends above (or below) the arrowhead, this represents the potential for customer rates to be higher (or
lower) than the base case outcomes. It should be noted that there is considerable overlap in the range of
estimated rates, and while base case estimates show higher rates for the CCE program, any of the CCE
Scenarios could potentially result in lower ratepayer costs than under the status quo. The sensitivity analysis
for the Community Participation (Small JPA) and Perfect Storm conditions are discussed above but not
included in Figure 25 as they are very unlikely to occur and would distort the results presented in the figure.
Rate outcomes for all conditions analyzed are included in Table 28 and Figures 26 and 27.
32 The ranges shown in Figure 25 do not include the Small JPA and Perfect Storm sensitivities.
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Section 6: Sensitivity Analyses Page 67
Figure 25: Sensitivity Analysis Range of Levelized Electric Rates
The sensitivity to each tested variable is shown in the following table. Natural Gas/Power prices and PG&E
Surcharges had the greatest impact on SVCCE rates in Scenarios 1 and 2, while renewable energy costs were
an increasingly important driver of SVCCE rates in Scenarios 3. Table 28 provides additional detail
regarding potential impacts to SVCCE and PG&E rates that could result under each sensitivity variable.
Table 28: Sensitivity Analysis - Levelized Ratepayer Costs (Cents Per KWh)
Rate
Scenario
Base
Case
High
Gas/
Power
Low
Gas/
Power
High
R.E.
Costs
Low
R.E.
Costs
High
PG&E
Rates
Low
PG&E
Rates
High
PCIA
Low
PCIA
High
Opt
Out
Low
Opt
Out
High
Carbon
Free
Cost
Small
JPA
Perfect
Storm
CCE
Scenario 1
21.5 22.4 21.0 22.1 20.8 21.5 21.5 22.4 20.5 21.5 21.4 21.7 22.3 23.9
CCE
Scenario 2
21.8 22.7 21.4 22.5 21.1 21.8 21.8 22.8 20.8 21.8 21.7 22.0 22.4 24.2
CCE
Scenario 3
22.3 23.2 21.8 23.1 21.4 22.3 22.3 23.2 21.3 22.3 22.2 22.4 22.8 24.8
PG&E
Bundled
22.3 22.9 21.9 22.3 22.3 23.8 21.6 22.3 22.3 22.3 22.3 22.3 22.3 21.6
The sensitivity results for each SVCCE supply scenario are depicted graphically in the following figures.
18.0
19.0
20.0
21.0
22.0
23.0
24.0
25.0
CCA Scenario 1 CCA Scenario 2 CCA Scenario 3 PG&E Bundled
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Figure 26: Scenario 1 Sensitivity Impacts on Levelized Electric Rates
Figure 27: Scenario 2 Sensitivity Impacts on Levelized Electric Rates
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Section 6: Sensitivity Analyses Page 69
Figure 28: Scenario 3 Sensitivity Impacts on Levelized Electric Rates
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Page 70 Section 7: Risk Analysis
SECTION 7: RISK ANALYSIS
CCE formation is not without risk, and a key element of this Study is highlighting risks that may be faced by
the CCE program as well as related risk-mitigation measures. Several of the quantitative impacts associated
with key risks have been addressed in Section 6, Sensitivity Analyses. However, there are additional risk
elements of which any aspiring CCE program should be aware as well as associated mitigation measures for
such risks. In particular, these additional risks include, but are not limited to, the following:
• Financial risks to SVCCE’s member municipalities in the unlikely event of CCE failure;
• Financial risks that may exist in the event that procured energy volumes fall short of or exceed actual
customer energy use;
• Reasonably foreseen legislative and regulatory changes, which may limit a CCE’s ability to remain
competitive with the incumbent utility;
• Availability of renewable and carbon-free energy supplies required to meet compliance mandates,
SVCCE program goals, and customer commitments; and
• General market volatility and price risk.
Financial Risks to SVCCE Members
In general terms, the prospective financial risks to SVCCE members will be limited to the extent that the JPA
agreement creates separation, also referred to as a “firewall”, between the financial assets and obligations
of the JPA and those of its individual members. This approach has been effectively employed by both MCE
and SCP at the time that each JPA was created, insulating the respective members of each organization from
the financial liabilities independently incurred by the JPA (e.g., power purchase agreements, debt, letters of
credit and other operating expenditures). For example, if the JPA was to default on a contract obligation,
any termination payments would be owed by the JPA and not the individual members, as individual JPA
members would not be responsible for the financial commitments of the JPA. From a practical perspective,
each member of the JPA would have a relatively small financial exposure, which would be limited to any
early-stage contributions and/or expenditures related to the CCE initiative before joining the JPA. After
joining the JPA, each participating municipality would be financially insulated via the JPA agreement, and it is
anticipated that the JPA would be financially independent during ongoing CCE operations, meaning that the
JPA would be responsible for independently demonstrating creditworthiness when entering into power
purchase agreements and financial covenants. Based on PEA’s understanding, qualified legal counsel was
engaged during the formation of each operating, multi-jurisdiction CCE to ensure that the associated JPA
agreement created the desired financial protections for its members.
Other than relatively small upfront costs/contributions that may be incurred by the JPA members during CCE
evaluation and JPA formation and any guarantees that may be offered to support startup, financial
obligations of the participating communities would be limited to individual customer impacts in the event of
outright CCE failure. In such a scenario, the $100,000 CCE bond is intended to cover the costs of returning
customers to PG&E service. However, following an involuntary return to bundled service, CCE customers would
be individually required to pay the PG&E Transitional Bundled Commodity Cost (TBCC), which imposes a
market-based rate on customers who fail to provide PG&E with six-month advance notice prior to
reestablishing PG&E electric service.33 In recent years, the TBCC rate has likely benefited participating
customers due to historically low market prices (and the favorable relationship of such prices to PG&E’s
generation rates). However, inherent price volatility within the electric power sector could result in relatively
high customer costs in the short-term, following an involuntary return to bundled service at a time when market
33 http://www.pge.com/tariffs/tm2/pdf/ELEC_SCHEDS_TBCC.pdf
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Section 7: Risk Analysis Page 71
prices are higher than PG&E’s prevailing generation rates. Depending on future market conditions during a
time of involuntary customer return to PG&E service, cost impacts during the six-month transition period could
be +/-25% (or more, depending on actual market prices) relative to otherwise applicable PG&E rate
schedules. In practical terms, the likelihood of this risk materially impacting a SVCCE customer appears to be
quite low.
In addition to the aforementioned financial risks to the JPA and its respective members, it is also noteworthy
that a subset of the CCE Study Partners, including the cities of Sunnyvale, Cupertino and Mountain View as
well as Santa Clara County, have entered into a project funding agreement to facilitate CCE program
evaluation, formation and implementation – these communities have made certain financial expenditures to
provide for the evaluation of prospective CCE formation. PEA also understands that this subset of the CCE
Study Partners, as well as other project participants, may choose to make additional contributions for
purposes of completing SVCCE’s formative and start-up activities. At the time of JPA formation, PEA
understands that certain CCE Study Partners may request repayment of the noted initial expenditures
following successful launch of the SVCCE program and a yet-to-be-defined period of successful operations.
Clearly, the repayment of such funding is dependent upon the successful launch and operation of the SVCCE
program.
For example, if SVCCE fails to launch or discontinues business operations prior to repaying initial funding
contributed by certain of the CCE Study Partners, then such Partners run the risk of financial losses equivalent
to any amounts expended in advance of such circumstances. With regard to the risk of the CCE Study
Partners losing its initial investment in CCE evaluation and formation, failure to launch the SVCCE program
represents the primary risk in this regard. Once SVCCE has launched and is serving customers, it is reasonable
to assume that the financial contributions that were previously made by certain CCE Study Partners would be
paid back within the first five years of SVCCE operation. Based on recent discussions and general enthusiasm
related to the SVCCE initiative, it seems reasonable to assume that the SVCCE program will launch as
planned, unless market conditions significantly change such that initial SVCCE rates are projected to exceed
similar rates charged by PG&E. Under Scenario 2, for example, sensitivity analyses suggest that power costs
could increase by 14% or PG&E rates could decrease by 11% (or a related combination of such impacts)
before projected SVCCE rates would exceed PG&E’s projected rates. From a practical perspective, this
observation suggests that current operating projections provide considerable safety margins for SVCCE,
allowing for a range of market conditions and/or rate changes before rate competitiveness would be
compromised. It is noteworthy that PG&E’s 2016 rates will remain unknown until January, and power costs
won’t be known until SVCCE issues a related solicitation for such products, which is expected to occur in early
2016. In the event that actual PG&E rate changes and/or proposed power prices fall outside of the
aforementioned safety margins, SVCCE would likely defer program launch and cease incurring startup
expenses until projected operations improve, potentially jeopardizing or delaying the reimbursement of
funding initially provided by certain of the CCE Study Partners.
Deviations between Actual Energy Use and Contracted Purchases
Deviations between actual customer energy use and contracted energy purchases are inevitable. For
example, weather variation may impose meaningful day-to-day variances in expected customer energy use,
which results in the potential for ongoing imbalances between procured energy volumes and actual electric
energy consumption by SVCCE’s customer base. To the extent that such imbalances exist, the CCE may be
required to make market purchases during unexpected price spikes and/or sell off excess energy volumes at
times when prices are relatively low (when compared to the price paid for such energy), which could impose
adverse financial impacts on the CCE program. Again, this is an inevitable risk that is assumed by all energy
market participants, but prudent planning and procurement practices can be utilized by the CCE to manage
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such risk to acceptable levels. In particular, “laddered” procurement strategies can be highly effective in
mitigating such risks – this procurement strategy is designed to promote increased cost/rate certainty during
the upcoming 12-month operating period by securing 90-100% of the CCE’s projected energy requirements
during this period of time. Beyond the 12-month operating horizon, an increasing proportion of the CCE’s
anticipated energy requirements are left “open” (i.e., are not addressed via contractual commitments) to
avoid financial commitments based on reduced planning certainty. For example, the CCE program may
decide that it is acceptable to take on market price risk associated with 5% of its expected energy
requirements over the upcoming 12-month operating period – this strategy would create cost certainty for a
significant portion of the CCE’s expected energy requirements, allowing the CCE to set rates in consideration
of such costs with minimal financial/budgetary risk. For months 13-24, the CCE would reduce forward supply
commitments to a level approximating 80-90% of expectations; for months 25-36, the CCE would further
reduce forward supply commitments to a level approximating 70-80% of expectations. Forward
procurement commitments would continue to “fall down the ladder” in subsequent months, but such open
positions are ultimately filled with time. It is also noteworthy that such percentages could always be adjusted
in consideration of prevailing market prices and the CCE’s overall risk tolerance.
This procurement strategy avoids the prospect of over-procurement and minimizes the prospect of surplus
energy sales while also allowing the CCE program to take advantage of favorable procurement opportunities
that may come about with time. During early-stage CCE operations, this strategy is particularly useful since
the CCE is unlikely to know exact customer participation levels. Over time, as the CCE’s customer base
becomes more stable/predictable, it will become less challenging to predict customer usage patterns.
Furthermore, a laddered procurement strategy allows the CCE’s portfolio composition to evolve over time as
opposed to committing to a specific resource mix that would only be minimally adjustable (subject to potential
adverse economic consequences) until related power supply agreements had expired.
Legislative and Regulatory Risk
California’s operating CCEs can attest to the challenges presented by anti-CCE legislation – a range of tactics
have been employed over time, pre-dating MCE’s launch in May, 2010 and resurfacing thereafter in various
forms. Ongoing issues continue to arise with regard to proposed legislation designed to assign/shift costs for
purposes of competitively disadvantaging CCE programs and/or limit the autonomy of CCE programs, so that
such programs appear more similar to their investor-owned counterparts. Recently, SB 350 and AB 1110
presented such issues. However, California’s operating CCEs were able to address many of the potentially
detrimental changes included within these bills through effective lobbying and technical support. California’s
IOUs regularly rely on professional lobbyists to promote their respective interests within the California
legislature, and CCEs have successfully employed similar tactics to represent their own interests, which often
differ from those of their investor-owned counterparts. Use of lobbyists within proximity to the State Capitol
also mitigates logistical challenges that may be encountered when addressing time-sensitive issues that require
on-site meeting participation and collaboration.
CCEs have also enjoyed similar success in California’s regulatory arena by utilizing the expertise of
specialized regulatory support, including qualified regulatory counsel and analysts, who have deep and long-
standing familiarity with a broad range of regulatory proceedings, assigned commissioners, judges and
support staff within jurisdictional agencies. Because certain proceedings have the potential to directly affect
the formation and ongoing operation of CCE programs, it is critically important to retain such expertise for
purposes of representing the CCEs interests, particularly if the CCE has not yet hired internal regulatory
counsel and/or staff. Over time, the CCE program may choose to scale its internal regulatory staffing in
consideration of the level of work required to achieve successful regulatory representation and desired
outcomes.
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Regarding recent legislation, on October 7, 2015, Governor Brown signed Senate Bill 350, the Clean Energy
and Pollution Reduction Act of 2015, enacting pertinent clean energy mandates reflected in this legislation. In
particular, SB 350 increases California’s RPS to 50% by 2030 amongst other clean-energy initiatives. Many
details regarding implementation of SB 350 will be developed over time with oversight by applicable
regulatory agencies. With regard to other relevant changes that have been created by SB 350, CCEs should
be aware of the following:
Costs associated with the integration of new renewable infrastructure may be off-set by a CCE if it
can demonstrate to the CPUC that it has already provided equivalent resources [Sections 454.51(d)
and 454.52(c)];
CCEs will be required to submit Integrated Resource Plans to the CPUC for certification while retaining
the governing authority and procurement autonomy administered by their respective governing
boards [Section 454.52(b)(3)];
The CPUC is now responsible for ensuring that: (1) IOU bundled customers do not incur any cost
increases as a result of customers participating in CCE service options, and (2) CCE customers do not
experience any cost increases as a result of IOU cost allocation that is not directly related to such CCE
customers (Sections 365.2 and 366.3);
Beginning in 2021, CCEs must have at least 65% of their RPS procurement under long-term contracts
of 10 years or more [Section 399.13(b)]; and
CCE energy efficiency programs will be able to count towards statewide energy efficiency targets
[Sections 25310(d)(6) and 25310(d)(8)].
In aggregate, the CCE-specific changes reflected in SB 350 are generally positive, providing for ongoing
autonomy with regard to resource planning and procurement. CCEs must be aware, however, of the long-
term contracting requirement associated with renewable energy procurement. This is not expected to present
issues for SVCCE, but planning and procurement efforts will need to consider this requirement during ongoing
operation of the CCE program.
AB 1110, which is now a two-year bill, was primarily focused on the addition of GHG emission disclosures
within the Power Content Label. During discussion in the recent legislative session, CCE interests were
generally concerned that the emissions methodology reflected in the bill was designed in a manner that was
not necessarily consistent with retail-level emissions reporting conventions used throughout the electric utility
industry and also appeared to diminish the environmental value of certain clean energy products. On
September 8, 2015, AB 1110 was ordered to the inactive file at the request of Senator Wolk.34 With this
direction in mind, AB 1110 is no longer an issue in the current legislative session. However, PEA recommends
that the CCE Study Partners should continue to monitor the legislature’s interest in promoting certain reporting
changes reflected in AB 1110, as such changes could narrow the potential field of cost-effective supply
options that could be pursued by SVCCE at some point in the future. The AB 1110 GHG emissions reporting
methodology may also present methodological conflicts with other programs, such as The Climate Registry,
which may be of interest to SVCCE at some point in the future.
Another piece of pending legislation that could pose direct and indirect impacts on CCE programs is SB 286
(Hertzberg). SB 286 was originally introduced during the 2015 legislative session (has now been converted
into a two-year bill) with the goal of increasing the direct access participatory cap by approximately 33%.
In its current form, SB 286 suggests that new direct access customers would be required to contract for 100%
34 AB 1110 bill history: http://leginfo.legislature.ca.gov/faces/billHistoryClient.xhtml?bill_id=201520160AB1110.
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renewable energy. If passed during the 2016 legislative session, SB 286 could either spark additional
renewable development, which could keep prices stable, or push renewable prices upward due to the
increased demand. Additionally, raising the direct access cap could put more pressure on CCE programs to
offer even more price competitive products to retain large commercial and industrial customers.
Regulatory risks include the potential for utility generation costs to be shifted to non-bypassable and delivery
charges. Examples include: 1) the Cost Allocation Mechanism (“CAM”), under which the costs of certain
generation commitments made by the investor owned utilities deemed necessary for grid reliability or to
support other state policy, are allocated to non-bundled (CCE and direct access) customers; and 2) the PCIA
as previously discussed.
CAM is a mechanism that allows investor owned utilities to impose a portion of the costs associated with their
power purchases onto CCE customers, even though these purchases are for fossil fuel resources with prices that
are often above current market levels. In theory, the goal of CAM is to promote grid reliability and should
only be applied to resources that contribute in that regard; in practical terms, the investor owned utilities have
obtained CPUC-approved CAM treatment for many types of generating resources. Bundled, CCE, and direct
access customers pay for CAM in the form of the New System Generation Charge (“NSGC”). The NSGC
imposes costs on CCE customers that often seem to be duplicative in light of long-term capacity commitments
that have already been made by CCEs in the form of various power purchase agreements (which can include
capacity attributes as an element of the purchased product). In other words, the present CAM methodology
does not appear to adequately reflect the contribution being made by CCEs in terms of promoting capacity
buildout within California’s energy market and generally undermines CCE procurement autonomy through the
imposition of costs that are not associated with contracts voluntarily entered into by the CCE.
One of the only tangible benefits realized by CCE’s under the current CAM rules is an offsetting capacity
allocation, which slightly reduces monthly resource adequacy requirements of the CCE entity. As previously
noted, the passage of SB 350 requires that CCEs have at least 65% of applicable RPS procurement under
long-term contracts, and existing CCEs have already demonstrated a track record of long term contracting
notwithstanding the pending requirements of SB 350. Such contracts typically confer capacity benefits
associated with the contracted resources, which could result in diminished value of CAM capacity allocations,
as many CCEs would have already procured a significant portion of applicable capacity requirements
through requisite renewable energy contracting efforts – stated somewhat differently, the CAM charges
imposed on CCE customers would result in little capacity value for CCE customers due to the fact that many
CCEs would have already arranged for such capacity under requisite long-term contract arrangements.
Another significant regulatory risk relates to changes that may occur with regard to the CCE Bond amount.
Currently, the $100,000 bond amount is quite manageable for aspiring CCE initiatives, but this could change
dramatically in the event that a larger bond amount, based on market conditions at the time of an involuntary
return of customers to bundled service, is established at some point in the future. PEA recommends that the
CCE Study Partners actively monitor and participate in, as necessary, related regulatory proceedings to
ensure that this item does not become a barrier for CCE formation or ongoing operation. As previously noted,
retention of an experienced lobbyist and qualified regulatory expertise will serve to manage and mitigate
the aforementioned risks.
Availability of Requisite Renewable and Carbon-Free Energy Supplies
California’s recent adoption of a 50% RPS has prompted various questions regarding the sufficiency of
renewable generating capacity that may be available to support compliance with such mandates. In
particular, both new and existing CCEs, which will be subject to prevailing RPS procurement mandates,
represent a growing pool of renewable energy buyers that will be “competing” for requisite in-state
resources. While this is certainly a legitimate concern, particularly when considering that the potential for CCE
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expansion throughout California seems quite significant, it is highly unlikely that any CCE buyer would be
unable to meet applicable procurement mandates during the ten-year planning horizon. To date, renewable
energy contracting opportunities within California have been abundant, providing interested buyers with cost-
competitive procurement opportunities well in excess of compliance mandates and voluntary renewable
energy procurement targets that have been established by certain CCEs. Furthermore, to the extent that
additional CCE programs continue to form, California’s largest buyers of renewable energy, represented by
the three investor-owned utilities, will have diminished renewable energy procurement obligations as a result
of decreasing retail sales. Certainly, the potential exists for increased supply costs as additional CCE buyers
compete for available renewable projects, but the general availability of such projects does not seem to be a
significant issue that will face SVCCE over the ten-year planning horizon. It is also reasonable to assume that
California-based project developers will be competing for buyers in the sense that prospective renewable
development opportunities (i.e., potential renewable generating capacity) may actually exceed statewide
demand. This circumstance has occurred in the past, particularly when California’s largest renewable energy
buyers, the IOUs, have met applicable renewable energy procurement targets – in these instances, project
developers are forced to “compete” for other buyers, including CCEs, which have benefited from very
favorable pricing for both short- and long-term transactions.
Additionally, as the operational and future CCE’s strive to meet high carbon-free energy targets, there is
some uncertainty around the availability of hydroelectric generation resources within California and
throughout the Pacific Northwest to meet such goals. Outside of renewable energy resources, hydroelectric
generation is the lowest cost means of meeting carbon-free objectives (keeping in mind that nuclear
generation will be excluded from SVCCE’s supply portfolio) but also comes with certain variability in supply.
Given the variability of such resources (i.e., wet versus dry year) and unpredictability of the day-to-day
energy deliveries, there is risk in achieving carbon content goals. There is also a cost risk associated with the
transmission of out-of-state hydroelectric generation into California during certain times of the year when
California energy buyers are seeking to import peak hydro season production – this congestion risk could add
significant costs to contracted hydroelectric power. To the extent that necessary hydroelectric power supply is
not available, the CCE program may choose to incorporate additional renewable energy supply, likely at an
increased cost, to ensure that emission reduction commitments can be satisfied.
Market Volatility and Price Risk
Wholesale energy markets are subject to sudden and significant volatility, resulting from myriad factors,
including but not limited to the following: weather, natural disasters, infrastructure outages, legislation and
implementing regulations, and natural gas storage levels. Over the past 24 months (or longer), wholesale
energy prices have fallen to near-historic lows, providing a favorable environment for buyers of electric
energy. An abundance of domestic natural gas supply, particularly shale gas, and strong storage levels have
also suppressed electric energy pricing, which will likely promote the continued trend of relatively low prices
for the foreseeable future. However, unexpected circumstances can impose abrupt changes to available
pricing, which necessitates a thoughtful, disciplined approach to managing such risk. The following figure,
provided by the CAISO, illustrates historic volatility in the wholesale electricity market, including a nearly 40%
reduction in such prices over the past 24 months.35
35 California ISO Q2 2015 Report on Market Issues and Performance, August 17, 2015.
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Figure 29: Historical Wholesale Electricity Price Curve
As previously described, a laddered procurement strategy will serve to mitigate wholesale pricing impacts at
any single point in time. Much like dollar cost averaging in the financial sector, laddered procurement
strategies serve to mask the impacts of periodic price spikes and troughs by blending the financial impacts
associated with such changes through a temporally diversified supply portfolio. For example, Table 29
reflects typical guidelines associated with a laddered procurement strategy – such strategies generally
attempt to balance the interests of near-term planning and budgetary certainty while moderating market
price risks at any single point in time. Based on the declining percentages reflected in Table 29, this balance
could be reasonably achieved while allowing for the inclusion of other, future contracting opportunities as well
as planned efficiency and demand-side impacts. Such strategies have been successfully implemented by
other CCE programs and are generally recognized as a prudent planning/procurement strategy. Note that
the percentages reflected in Table 29 may vary in consideration of the buyer’s unique preferences and
tolerance for risk.
Table 29: Indicative Contracting Guidelines under a Laddered Procurement Strategy
Time Horizon Contracting Guideline (Contractual Commitments/Total Energy Need)
Current Year 80% to 100%
Year 2 70% to 100%
Year 3 60% to 95%
Year 4 and Beyond Up to 70%
This procurement strategy should also create a certain level of symmetry with market impacts that would also
affect incremental procurement completed by the incumbent utility. Ultimately, there is no mitigation tactic
that could completely insulate the CCE from market price risk, but a diversified supply portfolio, in terms of
transaction timing, fuel sources and contract term lengths, will minimize such risks over time.
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SECTION 8: CCE FORMATION ACTIVITIES
This section provides a high level summary of the main steps involved in forming a CCE program that
culminates in the provision of service to enrolled customers. Key implementation activities include those related
to 1) CCE entity formation; 2) regulatory requirements; 3) procurement; 4) financing; 5) organization; and 6)
customer noticing. Completion of these activities is reflected in the Study’s startup cost estimates.
CCE Entity Formation
Unless the municipal organization that will legally register as the CCE entity already exists, it must be legally
established. Municipalities electing to offer or allow others to offer CCE service within their jurisdiction must
do so by ordinance. As anticipated for SVCCE, a joint power authority (“JPA”), the members of which will
include certain or all municipal jurisdictions currently represented amongst the CCE Study Partners, will be
formed via a related agreement amongst the participating municipalities. Specific examples of applicable
JPA agreements are available for currently operating CCE programs, including MCE and SCP, which were
formed under this joint structure. Based on PEA’s understanding, specific details related to SVCCE’s JPA
agreement are being developed.
Regulatory Requirements
Before aggregating customers, the CCE program must meet certain requirements set forth by the CPUC. In the
case of SVCCE, an Implementation Plan must be adopted by the joint powers authority, and that
Implementation Plan must be submitted to the CPUC. The Implementation Plan must include the following:
An organizational structure of the program, its operations, and its funding;
Ratesetting and other costs to participants;
Provisions for disclosure and due process in setting rates and allocating costs among participants;
The methods for entering and terminating agreements with other entities;
The rights and responsibilities of program participants, including, but not limited to, consumer
protection procedures, credit issues, and shutoff procedures;
Termination of the program; and
A description of the third parties that will be supplying electricity under the program, including, but
not limited to, information about financial, technical, and operational capabilities.
A Statement of Intent must be included with the Implementation Plan that provides for:
Universal access
Reliability
Equitable treatment of all classes of customers
Any requirements established by law or the CPUC concerning aggregated service.
The CPUC has ninety days to complete a review and certify the Implementation Plan though previous
Implementation Plan reviews completed on behalf of other California CCE programs have required far less
time. Following certification of the Implementation Plan, the CCE entity must submit a registration packet to
the CPUC, which includes:
An executed service agreement with PG&E, which may require a security deposit; and
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A bond or evidence of sufficient insurance to cover any reentry fees that may be imposed against it
by the CPUC for involuntarily returning customers to PG&E service. As previously noted, the current
CCE bond amount is $100,000.
The CCE program would be required to participate in the CPUC’s resource adequacy program before
commencing service to customers by providing load forecasts and advance demonstration of resource
adequacy compliance. More specifically, a start-up CCE program would be required to file a formal load
forecast with the CEC upon execution of a primary supply contract, which triggers a 100% commitment to
program launch.
Procurement
Power supplies must be secured several months in advance of commencing service. Power purchase
agreements with one or more power suppliers would be negotiated, typically following a competitive
selection process. Services that are required include provision of energy, capacity, renewable energy and
scheduling coordination. Once a firm commitment to offering CCE service is made, typically through execution
of power supply contracts, the CCE should provide its inaugural load forecast to the California Energy
Commission to initiate determination of the applicable resource adequacy requirements (i.e., capacity) for the
first year of operation.
Financing
Funding must be obtained to cover start-up activities and working capital needs. Start-up funding would be
secured early in the implementation process as these funds would be needed to conduct the critical activities
leading up to service commencement. Working capital lender commitments should be secured well in
advance, but actual funding need not occur until near the time that service begins.
Organization
Initial staff positions would be filled several months in advance of service commencement to conduct the
implementation process. Initially, internal staff of the CCE program may be relatively small but this would
likely change in the event that the CCE determines to insource various administrative and operational
responsibilities and/or develops and administers new programs for its customers. Contracts with other service
providers, such as for data management services, would be negotiated and put into effect well in advance of
service commencement.
Customer Notices
Customers must be provided notices regarding their pending enrollment in the CCE program. Such notices
must contain program terms and conditions as well as opt-out instructions and must be sent to prospective
customers at least twice within the sixty-day period immediately preceding automatic enrollment. These
notices are referred to as “pre-enrollment” notices. Two additional “post-enrollment” notices must be
provided within the sixty-day period following customer enrollment during the statutory opt-out period.
Ratesetting and Preliminary Program Development
As a California CCE, SVCCE would have independent ratesetting authority with regard to the electric
generation charges imposed on its customers. Prior to service commencement, SVCCE would need to establish
initial customer generation rates for each of the customer groups represented in its first operating phase or
for all prospective customers within the CCE’s prospective service territory. SVCCE may decide to create a
schedule of customer generation rates that generally resembles the current rate options offered by PG&E.
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This practice would facilitate customer rate comparisons and should avoid confusion that may occur if
customers were to be transitioned to dissimilar tariff options. SVCCE would need to establish a schedule for
ongoing rate updates/changes for future customer phases and ongoing operations.
SVCCE may also choose to offer certain customer-focused programs, such as Net Energy Metering (“NEM”),
voluntary green pricing and/or FIT programs, at the time of service commencement. To the extent that SVCCE
intends to offer such programs, specific terms and conditions of service would need to be developed in
advance of service commencement.
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SECTION 9: EVALUATION AND RECOMMENDATIONS
This section provides an overall assessment of the feasibility for forming a CCE program serving communities
of the CCE Study Partners and provides PEA’s recommendations in the event a decision is made to proceed
with development of the SVCCE program.
PEA’s analysis suggests that SVCCE could provide significant benefits – both economic and environmental –
which could be accomplished under certain prospective operating scenarios with customer rates that are
competitive, if not lower than, current rate projections for PG&E. Under a reasonable range of sensitivity
assumptions, the analysis shows that customer rates are projected to range from approximately 21 to 23
cents per kWh, on a ten-year levelized cost basis, while PG&E rates are projected to range from 22 to 24
cents per kWh on a levelized basis over this same period of time.
Under base case assumptions, CCE program rates are projected to range from 21.5 cents per kWh to 22.3
cents per kWh, depending upon the ultimate CCE program resource mix. PG&E’s generation rate is projected
to be 22.3 cents per kWh, creating the potential for customer savings under two of the three supply scenarios.
Table 30 shows projected levelized electric rates and typical residential monthly electric bills under the base
case assumptions.
Table 30: Summary of Ratepayer Impacts
Ratepayer Impact Scenario 1 Scenario 2 Scenario 3 PG&E
Levelized Electric Rate (Cents/KWh) 21.5 21.8 22.3 22.3
Typical Residential Bill ($/Month)36 $112 $114 $116 $116
It should be noted that there is considerable overlap in the range of estimated rates under the various
sensitivity scenarios described in this Study, and while base case estimates generally show highly competitive
rates for the CCE program, it is anticipated that Scenarios 1 and 2 are most likely to generate customer rate
savings while Scenario 3 is most likely to result in general cost equivalency over time.
With regard to GHG emissions impacts, the ultimate resource mix identified by the CCE program will dictate
actual GHG emissions impacts created by SVCCE operation. Depending upon resource choices made by the
CCE program, potential GHG emissions may vary widely relative to PG&E. For example, under Scenario 1,
SVCCE should assume zero electric power sector GHG emissions impacts within communities of the CCE Study
Partners. Scenarios 2 and 3 are both expected to create significant GHG emissions reductions through the
procurement of significant quantities of renewable and additional carbon-free energy. Table 31 summarizes
projected GHG emissions impacts for each of the modeled supply scenarios.
36 Average monthly residential electricity consumption within communities of the CCE Study Partners is approximately 510
kWh.
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Table 31: GHG Emissions Impacts (Ten Year Average)
GHG Impact Scenario 1 Scenario 2 Scenario 3
Annual Change in GHG Emissions (Tons
CO2/Year) Zero -82,659 -310,504
Change in Electric Sector CO2 Emissions
within Communities of the CCE Study
Partners (%)
Zero -20% -73%
Projected SVCCE Portfolio Emissions
Factor (metric tons/MWh) 0.128 0.103 0.034
Projected PG&E Portfolio Emissions
Factor (metric tons/MWh) 0.128 0.128 0.128
Figure 30 illustrate projected GHG emissions from CCE program customer under the status quo as well as
each of the prospective SVCCE supply scenarios. When reviewing Figure 30, note that the sharp increase in
emissions between year one and year three is directly related to SVCCE’s phased customer enrollment
schedule – during this three-year period, total emissions are expected to increase as customers are added to
the SVCCE program. Following full enrollment in year three, SVCCE portfolio emissions gradually decline
over time as increased quantities of carbon-free energy sources are increasingly reflected in the overall
SVCCE resource mix. Note that the projected GHG emissions trend associated with Scenario 1 coincides with
the PG&E reference line, as there are zero assumed GHG emissions reductions under this planning scenario.
Figure 30: Projected GHG Emissions
The potential for local generation investment arising from the CCE program appears to offer significant
benefits to the local economy. Again, resource decisions will impact the degree to which generation
investments yield local benefits as indicated through the analysis of local economic impact associated with the
representative supply scenarios. Compared to some other areas in the state, communities of the CCE Study
Partners are not the best resource areas for solar and wind production, and local projects of this type will
tend to have higher costs than projects sited in prime resource areas. Tradeoffs also exist between minimizing
ratepayer costs in the short run and expanding use of renewable energy due to the cost premiums that
currently exist for renewable energy. Decisions made during the implementation process and during the life
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of the CCE program will determine how these considerations are balanced. PEA recommends that
considerable thought be given upfront to the ultimate goals of the CCE program so that clear objectives are
established, giving those responsible for administering the CCE program the opportunity to develop and
execute resource management and procurement plans that meet objectives of the CCE Study Partners.
In summary, it is PEA’s opinion that, based on currently observed wholesale market conditions, anticipated
PG&E electric rates and certain of the supply scenarios evaluated in this Study, amongst various other
considerations, a CCE program serving customers within communities of the CCE Study Partners could offer
both economic (i.e., positive economic development impacts and overall cost savings for customers of the CCE
program) and environmental benefits during initial program operations and, potentially, throughout the ten-
year study period. As previously noted, due to the dynamic nature of California’s energy markets,
particularly market prices which are subject to frequent changes, the SVCCE Partnership should confirm that
the assumptions reflected in this Study generally align with future market conditions (observed at the time of
any decision by the SVCCE Partnership to move forward) to promote the achievement of early-stage SVCCE
operations that generally align with the operating projections reflected in this Study – to the extent that future
market price benchmarks materially differ from any of the assumptions noted in this Study, PEA recommends
updating pertinent operating projections to ensure well-informed decision making and prudent action related
to SVCCE program formation.
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Appendix A: SVCCE Pro Forma Analyses Page 83
APPENDIX A: SVCCE PRO FORMA ANALYSES
264
ORDINANCE NO. 15-2138
AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF CUPERTINO
AUTHORIZING THE IMPLEMENTATION OF A
COMMUNITY CHOICE AGGREGATION (CCA) PROGRAM
The City Council of the City of Cupertino does ordain as follows:
SECTION 1. FINDINGS. The City Council finds as follows:
1. The Cities of Cupertino, Mountain View and Sunnyvale and the County of Santa
Clara formed and sponsored the Silicon Valley Community Choice Energy
Partnership (SVCCEP) to investigate options to provide electric service to
customers within the City of Cupertino and surrounding municipalities with the
intent of achieving greater local control and involvement over the provision of
electric services, competitive electric rates, the development of local renewable
energy projects, reduced greenhouse gas emissions, and the implementation of
energy conservation and efficiency projects and programs.
2. The City of Cupertino, through its participation in SVCCEP, has prepared a
Technical Feasibility Study for a Community Choice Aggregation (“CCA”)
program under the provisions of Public Utilities Code Section 366.2. The
Technical Feasibility Study shows that implementing a community choice
aggregation program would likely provide multiple benefits, including the
following:
a. Providing customers a choice of power providers;
b. Increasing local control over energy rates and other energy-related matters;
c. Providing electric rates that are competitive with those provided by the
incumbent utility;
d. Reducing greenhouse gas emissions arising from electricity use in the City;
e. Increasing local and regional renewable generation capacity;
f. Increasing energy conservation and efficiency projects and programs;
g. Increasing regional energy self-sufficiency; and
h. Improving the local economy by implementing new local renewable and
energy conservation and efficiency projects.
3. The Joint Powers Agreement creating the Silicon Valley Clean Energy Authority
(“Authority”) will govern and operate the CCA program on behalf of its member
jurisdictions. The Initial Participants within the County of Santa Clara, as defined
by the Joint Powers Agreement, may participate in the Authority by adoption of
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Page 2
a resolution approving the execution of the Joint Powers Agreement and
adoption of the CCA ordinance required by Public Utilities Code Section
366.2(c)(12) by March 31, 2016. Municipalities choosing to participate in the
Authority will have membership on the Board of Directors of the Authority as
provided in the Joint Powers Agreement.
4. The Authority will enter into agreements with electric power suppliers and other
service providers and, based upon those agreements, the Authority plans to
provide electrical power to residents and businesses at rates that are competitive
with those of the incumbent utility. Once the California Public Utilities
Commission approves the implementation plan prepared by the Authority, the
Authority may provide service to customers within the City of Cupertino and
those cities that choose to participate in the Silicon Valley Clean Energy
Authority; and
5. Under Public Utilities Code Section 366.2, customers have the right to opt-out of
a CCA program and continue to receive service from the incumbent utility.
Customers who wish to continue to receive service from the incumbent utility
will be able to do so at any time; and
6. On December 1, 2016, the Cupertino City Council held a public hearing at which
time interested persons had an opportunity to testify either in support or in
opposition to implementation of the Silicon Valley Clean Energy CCA program
in the City of Cupertino; and
7. This ordinance is exempt from the requirements of the California Environmental
Quality Act (CEQA) pursuant to the State CEQA Guidelines, as it is not a
“project” and has no potential to result in a direct or reasonably foreseeable
indirect physical change to the environment. (14 Cal. Code Regs. § 15378(a).)
Further, the ordinance is exempt from CEQA as there is no possibility that the
ordinance or its implementation would have a significant negative effect on the
environment. (14 Cal. Code Regs.§ 15061(b)(3).) The ordinance is also
categorically exempt because it is an action taken by a regulatory agency to
assure the maintenance, restoration, enhancement or protection of the
environment. (14 Cal. Code Regs. § 15308.) A Notice of Exemption to be filed as
authorized by CEQA and the State CEQA Guidelines; and
8. The City Council is the decision-making body for the contemplated actions,
including enactment of this Ordinance; and
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9. The City Council has reviewed and considered the CEQA exemptions before
taking any approval actions on this Ordinance and finds such exemptions are
applicable.
SECTION 2. The above findings are true and correct.
SECTION 3. AUTHORIZATION TO IMPLEMENT A COMMUNITY CHOICE
AGGREGATION PROGRAM. Based upon the foregoing, and in order to provide
businesses and residents within the City of Cupertino with a choice of power providers,
the City of Cupertino hereby elects to implement a community choice aggregation
program within the jurisdiction of the City by participating in the Community Choice
Aggregation program of the Silicon Valley Clean Energy Authority, as described in its
Joint Powers Agreement.
SECTION 4. This Ordinance shall be in full force and effect thirty (30) days after its
adoption, and the City Clerk shall certify the adoption of this Ordinance and shall give
notice of its adoption as required by law. Pursuant to Government Code Section 36933,
a summary of this Ordinance may be published and posted in lieu of publication and
posting of the entire text.
INTRODUCED at a regular meeting of the City Council of the City of Cupertino
the 1st day of December, 2015 and ENACTED at a regular meeting of the City Council
of the City of Cupertino the ____ of _______ 2015, by the following vote:
Vote: Members of the City Council
Ayes:
Noes:
Absent:
Abstain:
ATTEST: APPROVED:
______________________ __________________________________
Grace Schmidt, City Clerk Mayor, City of Cupertino
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RESOLUTION NO. 15-111
A RESOLUTION OF THE CITY COUNCIL OF CUPERTINO APPROVING THE
JOINT POWERS AGREEMENT ESTABLISHING
THE SILICON VALLEY CLEAN ENERGY AUTHORITY
WHEREAS, the Cities of Cupertino, Mountain View and Sunnyvale and the County of
Santa Clara formed and sponsored the Silicon Valley Community Choice Energy
Partnership (SVCCEP) to investigate options to provide electric service to customers
within the City of Cupertino and surrounding municipalities with the intent of
achieving greater local control and involvement over the provision of electric services,
competitive electric rates, the development of local, renewable energy projects, reduced
greenhouse gas emissions, and the implementation of energy conservation and
efficiency projects and programs; and
WHEREAS, the City of Cupertino through its participation in SVCCEP has participated
in the preparation of a Technical Feasibility Study for a community choice aggregation
(“CCA”) program under the provisions of Public Utilities Code Section 366.2, with the
Technical Feasibility Study concluding that implementing a community choice
aggregation program would likely achieve the goals and benefits described above; and
WHEREAS, the City of Cupertino desires to enter into the Joint Powers Agreement
establishing the Silicon Valley Clean Energy Authority in order to implement a
community choice aggregation program pursuant to Public Utilities Code Section
366.2(c)(12) within the jurisdiction of the City along with the other municipalities that
become a member of the Authority;
NOW, THEREFORE, THE COUNCIL OF THE CITY OF CUPERTINO HEREBY
RESOLVES:
Section 1. The Silicon Valley Clean Energy Authority Joint Powers Agreement, attached
hereto, is herby approved and the Mayor is authorized to execute this Agreement upon
the effective date of this resolution with any minor changes to the Agreement approved
by the City Manager and City Attorney.
Section 2. This resolution and the establishment of the Silicon Valley Clean Energy
Authority is exempt from the requirements of the California Environmental Quality Act
(CEQA) pursuant to the State CEQA Guidelines, as it is not a “project” since this action
involves organizational and administrative activities of government that will not result
in direct or indirect physical changes in the environment. (14 Cal. Code Regs. §
15378(b)(5)). Further, the ordinance and resolution are exempt from CEQA as there is
no possibility that the ordinance or its implementation would have a significant
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Page 2
negative effect on the environment. (14 Cal. Code Regs.§ 15061(b)(3)). A Notice of
Exemption shall be filed as authorized by CEQA and the State CEQA guidelines. The
City Council is the decision-making body for the contemplated actions, including
approval of this Resolution. The City Council has reviewed and considered the CEQA
exemptions prior to taking any approval actions and finds such exemptions are
applicable.
Section 2. The Silicon Valley Clean Energy Authority Joint Powers Agreement, attached
hereto, is herby approved and the Mayor is authorized to execute this Agreement upon
the effective date of this resolution.
Section 3. This resolution shall be effective upon the adoption of Ordinance No. ______,
AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF CUPERTINO
AUTHORIZING THE IMPLEMENTATION OF A COMMUNITY CHOICE
AGGREGATION (CCA) PROGRAM.
PASSED AND ADOPTED this ______ day of ___________________, 2015, by the
following vote:
PASSED:
Vote: Members of the City Council
Ayes:
Noes:
Absent:
Abstain:
ATTEST: APPROVED:
______________________ __________________________________
Grace Schmidt, City Clerk Mayor, City of Cupertino
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Final Draft (11/25/15)
Silicon Valley Clean Energy Authority
- Joint Powers Agreement –
Effective _____________
Among The Following Parties:
City of Campbell
City of Cupertino
City of Gilroy
City of Los Altos
Town of Los Altos Hills
Town of Los Gatos
City of Monte Sereno
City of Morgan Hill
City of Mountain View
County of Santa Clara (Unincorporated Area)
City of Saratoga
City of Sunnyvale
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SILICON VALLEY CLEAN ENERGY AUTHORITY
JOINT POWERS AGREEMENT
This Joint Powers Agreement (“Agreement”), effective as of _________, is made and
entered into pursuant to the provisions of Title 1, Division 7, Chapter 5, Article 1 (Section 6500
et seq.) of the California Government Code relating to the joint exercise of powers among the
parties set forth in Exhibit B (“Parties”). The term “Parties” shall also include an incorporated
municipality or county added to this Agreement in accordance with Section 3.1.
RECITALS
1. The Parties are either incorporated municipalities or counties sharing various powers
under California law, including but not limited to the power to purchase, supply, and
aggregate electricity for themselves and their inhabitants.
2. The purposes for the Initial Participants (as such term is defined in Section 2.2 below)
entering into this Agreement include addressing climate change by reducing energy
related greenhouse gas emissions and securing energy supply and price stability, energy
efficiencies and local economic benefits. It is the intent of this Agreement to promote the
development and use of a wide range of renewable energy sources and energy efficiency
programs, including but not limited to solar and wind energy production.
3. The Parties desire to establish a separate public agency, known as the Silicon Valley
Clean Energy Authority (“Authority”), under the provisions of the Joint Exercise of
Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”) in
order to collectively study, promote, develop, conduct, operate, and manage energy
programs.
4. The Initial Participants have each adopted an ordinance electing to implement through the
Authority a Community Choice Aggregation program pursuant to California Public
Utilities Code Section 366.2 (“CCA Program”). The first priority of the Authority will be
the consideration of those actions necessary to implement the CCA Program.
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AGREEMENT
NOW, THEREFORE, in consideration of the mutual promises, covenants, and conditions
hereinafter set forth, it is agreed by and among the Parties as follows:
ARTICLE 1
CONTRACT DOCUMENTS
1.1 Definitions. Capitalized terms used in the Agreement shall have the meanings
specified in Exhibit A, unless the context requires otherwise.
1.2 Documents Included. This Agreement consists of this document and the
following exhibits, all of which are hereby incorporated into this Agreement.
Exhibit A: Definitions
Exhibit B: List of the Parties
Exhibit C: Annual Energy Use
Exhibit D: Voting Shares
Exhibit E: Funding of Initial Costs
1.3 Revision of Exhibits. The Parties agree that Exhibits B, C and D to this
Agreement describe certain administrative matters that may be revised upon the approval of the
Board, without such revision constituting an amendment to this Agreement, as described in
Section 8.4. The Authority shall provide written notice to the Parties of the revision of any such
exhibit.
ARTICLE 2
FORMATION OF SILICON VALLEY CLEAN ENERGY AUTHORITY
2.1 Effective Date and Term. This Agreement shall become effective and Silicon
Valley Clean Energy Authority shall exist as a separate public agency on March 31, 2016
provided that this Agreement is executed on or prior to such date by at least three Initial
Participants after the adoption of the ordinances required by Public Utilities Code Section
366.2(c)(12). The Authority shall provide notice to the Parties of the Effective Date. The
Authority shall continue to exist, and this Agreement shall be effective, until this Agreement is
terminated in accordance with Section 7.4, subject to the rights of the Parties to withdraw from
the Authority.
2.2 Initial Participants. Until March 31, 2016, all other Initial Participants may
become a Party by executing this Agreement and delivering an executed copy of this Agreement
and a copy of the adopted ordinance required by Public Utilities Code Section 366.2(c)(12) to the
Authority. Additional conditions, described in Section 3.1, may apply (i) to either an
incorporated municipality or county desiring to become a Party that is not an Initial Participant
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and (ii) to Initial Participants that have not executed and delivered this Agreement within the
time period described above.
2.3 Formation. There is formed as of the Effective Date a public agency named the
Silicon Valley Clean Energy Authority. Pursuant to Sections 6506 and 6507 of the Act, the
Authority is a public agency separate from the Parties. The debts, liabilities or obligations of the
Authority shall not be debts, liabilities or obligations of the individual Parties unless the
governing board of a Party agrees in writing to assume any of the debts, liabilities or obligations
of the Authority. A Party who has not agreed to assume an Authority debt, liability or obligation
shall not be responsible in any way for such debt, liability or obligation even if a majority of the
Parties agree to assume the debt, liability or obligation of the Authority. Notwithstanding
Section 8.4 of this Agreement, this Section 2.3 may not be amended unless such amendment is
approved by the governing boards of all Parties.
2.4 Purpose. The purpose of this Agreement is to establish an independent public
agency in order to exercise powers common to each Party and any other powers granted to the
Authority under state law to study, promote, develop, conduct, operate, and manage energy and
energy-related climate change programs, and to exercise all other powers necessary and
incidental to accomplishing this purpose. Without limiting the generality of the foregoing, the
Parties intend for this Agreement to be used as a contractual mechanism by which the Parties are
authorized to participate as a group in the CCA Program pursuant to Public Utilities Code
Section 366.2(c)(12). The Parties intend that subsequent agreements shall define the terms and
conditions associated with the actual implementation of the CCA Program.
2.5 Powers. The Authority shall have all powers common to the Parties and such
additional powers accorded to it by law. The Authority is authorized, in its own name, to
exercise all powers and do all acts necessary and proper to carry out the provisions of this
Agreement and fulfill its purposes, including, but not limited to, each of the following:
2.5.1 make and enter into contracts;
2.5.2 employ agents and employees, including but not limited to an Executive
Director;
2.5.3 acquire, contract, manage, maintain, and operate any buildings, works or
improvements;
2.5.4 acquire property by eminent domain, or otherwise, except as limited under
Section 6508 of the Act, and to hold or dispose of any property;
2.5.5 lease any property;
2.5.6 sue and be sued in its own name;
2.5.7 incur debts, liabilities, and obligations, including but not limited to loans
from private lending sources pursuant to its temporary borrowing powers
such as Government Code Section 53850 et seq. and authority under the
Act;
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2.5.8 issue revenue bonds and other forms of indebtedness;
2.5.9 apply for, accept, and receive all licenses, permits, grants, loans or other
assistance from any federal, state or local public agency;
2.5.10 submit documentation and notices, register, and comply with orders,
tariffs and agreements for the establishment and implementation of the
CCA Program and other energy programs;
2.5.11 adopt rules, regulations, policies, bylaws and procedures governing the
operation of the Authority (“Operating Rules and Regulations”); and
2.5.12 make and enter into service, energy and any other agreements necessary to
plan, implement, operate and administer the CCA Program and other
energy programs, including the acquisition of electric power supply and
the provision of retail and regulatory support services.
2.6 Limitation on Powers. As required by Government Code Section 6509, the
power of the Authority is subject to the restrictions upon the manner of exercising power
possessed by the City of Cupertino and any other restrictions on exercising the powers of the
Authority that may be adopted by the Board.
2.7 Compliance with Local Zoning and Building Laws. Notwithstanding any other
provisions of this Agreement or state law, any facilities, buildings or structures located,
constructed or caused to be constructed by the Authority within the territory of the Authority
shall comply with the General Plan, zoning and building laws of the local jurisdiction within
which the facilities, buildings or structures are constructed.
ARTICLE 3
AUTHORITY PARTICIPATION
3.1 Addition of Parties. Subject to Section 2.2, relating to certain rights of Initial
Participants, other incorporated municipalities and counties may become Parties upon (a) the
adoption of a resolution by the governing body of such incorporated municipality or county
requesting that the incorporated municipality or county, as the case may be, become a member of
the Authority, (b) the adoption by a two-thirds affirmative vote of the entire Board satisfying the
requirements described in Section 4.9, of a resolution authorizing membership of the additional
incorporated municipality or county, specifying the membership payment, if any, to be made by
the additional incorporated municipality or county to reflect its pro rata share of organizational,
planning and other pre-existing expenditures, and describing additional conditions, if any,
associated with membership, (c) the adoption of an ordinance required by Public Utilities Code
Section 366.2(c)(12) and execution of this Agreement and other necessary program agreements
by the incorporated municipality or county, (d) payment of the membership fee, if any, and (e)
satisfaction of any conditions established by the Board.
3.2 Continuing Participation. The Parties acknowledge that membership in the
Authority may change by the addition and/or withdrawal or termination of Parties. The Parties
agree to participate with such other Parties as may later be added, as described in Section 3.1.
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The Parties also agree that the withdrawal or termination of a Party shall not affect this
Agreement or the remaining Parties’ continuing obligations under this Agreement.
ARTICLE 4
GOVERNANCE AND INTERNAL ORGANIZATION
4.1 Board of Directors. The governing body of the Authority shall be a Board of
Directors (“Board”) consisting of one director for each Party appointed in accordance with
Section 4.2.
4.2 Appointment and Removal of Directors. The Directors shall be appointed and
may be removed as follows:
4.2.1 The governing body of each Party shall appoint and designate in writing
one regular Director who shall be authorized to act for and on behalf of the
Party on matters within the powers of the Authority. The governing body
of each Party also shall appoint and designate in writing one alternate
Director who may vote on matters when the regular Director is absent
from a Board meeting. The person appointed and designated as the
Director shall be a member of the governing body of the Party. The
person appointed and designated as the alternate Director may be a
member of the governing body of the Party, a staff member of the Party,
or a member of the public.
4.2.2 The Operating Rules and Regulations, to be developed and approved by
the Board in accordance with Section 2.5.11, shall specify the reasons for
and process associated with the removal of an individual Director for
cause. Notwithstanding the foregoing, no Party shall be deprived of its
right to seat a Director on the Board and any such Party for which its
Director and/or alternate Director has been removed may appoint a
replacement.
4.3 Terms of Office. Each regular and alternate Director shall serve at the pleasure of
the governing body of the Party that the Director represents, and may be removed as Director by
such governing body at any time. If at any time a vacancy occurs on the Board, a replacement
shall be appointed to fill the position of the previous Director in accordance with the provisions
of Section 4.2 within 90 days of the date that such position becomes vacant.
4.4 Quorum. A majority of the Directors of the entire Board shall constitute a
quorum.
4.5 Powers and Function of the Board. The Board shall conduct or authorize to be
conducted all business and activities of the Authority, consistent with this Agreement, the
Authority Documents, the Operating Rules and Regulations, and applicable law.
4.6 Executive Committee. The Board may establish an executive committee
consisting of a smaller number of Directors. The Board may delegate to the executive committee
such authority as the Board might otherwise exercise, subject to limitations placed on the
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Board’s authority to delegate certain essential functions, as described in the Operating Rules and
Regulations. The Board may not delegate to the Executive Committee or any other committee its
authority under Section 2.5.11 to adopt and amend the Operating Rules and Regulations.
4.7 Commissions, Boards and Committees. The Board may establish any advisory
commissions, boards and committees as the Board deems appropriate to assist the Board in
carrying out its functions and implementing the CCA Program, other energy programs and the
provisions of this Agreement.
4.8 Director Compensation. Compensation for work performed by Directors on
behalf of the Authority shall be borne by the Party that appointed the Director. The Board,
however, may adopt by resolution a policy relating to the reimbursement of expenses incurred by
Directors.
4.9 Board Voting.
4.9.1 Percentage Vote. Except when a supermajority vote is expressly required
by this Agreement or the Operating Rules and Regulations, action of the
Board on all matters shall require an affirmative vote of a majority of all
Directors on the entire Board. A supermajority vote is required by this
Agreement for the matters addressed by Sections 3.1, 6.4, 7.1.1, 7.1.2, 7.2,
and 8.4. When a supermajority vote is required by this Agreement or the
Operating Rules and Regulations, action of the Board shall require an
affirmative vote of the specified supermajority of all Directors on the
entire Board. All votes taken pursuant to this Section 4.9.1 shall be
referred to as a percentage vote. No action can be taken by the Board
without an affirmative percentage vote.
4.9.2 Voting Shares Vote. In addition to and immediately after an affirmative
percentage vote, two or more Directors may request that, a vote of the
voting shares shall be held. In such event, the corresponding voting shares
(as described in Section 4.9.2 and Exhibit D) of all Directors voting in the
affirmative shall exceed 50%, or such other higher voting shares
percentage expressly required by this Agreement or the Operating Rules
and Regulations, of all Directors on the entire Board. All votes taken
pursuant to this Section 4.9.2 shall be referred to as a voting shares vote.
In the event that any one Director has a voting share that equals or exceeds
that which is necessary to disapprove the matter being voted on by the
Board, at least one other Director shall be required to vote in the negative
in order to disapprove such matter. When a voting shares vote is held,
action by the Board requires both an affirmative percentage vote and an
affirmative voting shares vote.
4.9.3 Voting Shares Formula. When a voting shares vote is requested by two
or more Directors, voting shares of the Directors shall be determined by
the following formula:
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(Annual Energy Use/Total Annual Energy) multiplied by 100, where (a)
“Annual Energy Use” means (i) with respect to the first two years
following the Effective Date, the annual electricity usage, expressed in
kilowatt hours (“kWh”), within the Party’s respective jurisdiction and (ii)
with respect to the period after the second anniversary of the Effective
Date, the annual electricity usage, expressed in kWh, of accounts within a
Party’s respective jurisdiction that are served by the Authority and (b)
“Total Annual Energy” means the sum of all Parties’ Annual Energy Use.
The initial values for Annual Energy use are designated in Exhibit C and
the initial voting shares are designated in Exhibit D. Both Exhibits C and
D shall be adjusted annually as soon as reasonably practicable after
January 1, but no later than March 1 of each year subject to the approval
of the Board.
4.10 Meetings and Special Meetings of the Board. The Board shall hold at least four
regular meetings per year, but the Board may provide for the holding of regular meetings at more
frequent intervals. The date, hour and place of each regular meeting shall be fixed by resolution
or ordinance of the Board. Regular meetings may be adjourned to another meeting time. Special
meetings of the Board may be called in accordance with the provisions of California Government
Code Section 54956. Directors may participate in meetings telephonically, with full voting
rights, only to the extent permitted by law. All meetings of the Board shall be conducted in
accordance with the provisions of the Ralph M. Brown Act (California Government Code
Section 54950 et seq.).
4.11 Selection of Board Officers.
4.11.1 Chair and Vice Chair. The Directors shall select, from among
themselves, a Chair, who shall be the presiding officer of all Board
meetings, and a Vice Chair, who shall serve in the absence of the Chair.
The term of office of the Chair and Vice Chair shall continue for one year,
but there shall be no limit on the number of terms held by either the Chair
or Vice Chair. The office of either the Chair or Vice Chair shall be
declared vacant and a new selection shall be made if: (a) the person
serving dies, resigns, or the Party that the person represents removes the
person as its representative on the Board or (b) the Party that he or she
represents withdraws from the Authority pursuant to the provisions of this
Agreement.
4.11.2 Secretary. The Board shall appoint a Secretary, who need not be a
member of the Board, who shall be responsible for keeping the minutes of
all meetings of the Board and all other official records of the Authority.
4.11.3 Treasurer and Auditor. The Board shall appoint a qualified person to act
as the Treasurer and a qualified person to act as the Auditor, neither of
whom needs to be a member of the Board. If the Board so designates, and
in accordance with the provisions of applicable law, a qualified person
may hold both the office of Treasurer and the office of Auditor of the
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Authority. Unless otherwise exempted from such requirement, the
Authority shall cause an independent audit to be made by a certified public
accountant, or public accountant, in compliance with Section 6505 of the
Act. The Treasurer shall act as the depositary of the Authority and have
custody of all the money of the Authority, from whatever source, and as
such, shall have all of the duties and responsibilities specified in Section
6505.5 of the Act. The Board may require the Treasurer and/or Auditor to
file with the Authority an official bond in an amount to be fixed by the
Board, and if so requested, the Authority shall pay the cost of premiums
associated with the bond. The Treasurer shall report directly to the Board
and shall comply with the requirements of treasurers of incorporated
municipalities. The Board may transfer the responsibilities of Treasurer to
any person or entity as the law may provide at the time. The duties and
obligations of the Treasurer are further specified in Article 6.
ARTICLE 5
IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS
5.1 Preliminary Implementation of the CCA Program.
5.1.1 Enabling Ordinance. Prior to the execution of this Agreement, each Party
shall adopt an ordinance in accordance with Public Utilities Code Section
366.2(c)(12) for the purpose of specifying that the Party intends to
implement a CCA Program by and through its participation in the
Authority.
5.1.2 Implementation Plan. The Authority shall cause to be prepared an
Implementation Plan meeting the requirements of Public Utilities Code
Section 366.2 and any applicable Public Utilities Commission regulations
as soon after the Effective Date as reasonably practicable. The
Implementation Plan shall not be filed with the Public Utilities
Commission until it is approved by the Board in the manner provided by
Section 4.9.
5.1.3 Termination of CCA Program. Nothing contained in this Article or this
Agreement shall be construed to limit the discretion of the Authority to
terminate the implementation or operation of the CCA Program at any
time in accordance with any applicable requirements of state law.
5.2 Authority Documents. The Parties acknowledge and agree that the affairs of the
Authority will be implemented through various documents duly adopted by the Board through
Board resolution or minute action, including but not necessarily limited to the Operating Rules
and Regulations, the annual budget, and specified plans and policies defined as the Authority
Documents by this Agreement. The Parties agree to abide by and comply with the terms and
conditions of all such Authority Documents that may be adopted by the Board, subject to the
Parties’ right to withdraw from the Authority as described in Article 7.
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ARTICLE 6
FINANCIAL PROVISIONS
6.1 Fiscal Year. The Authority’s fiscal year shall be 12 months commencing July 1
and ending June 30. The fiscal year may be changed by Board resolution.
6.2 Depository.
6.2.1 All funds of the Authority shall be held in separate accounts in the name
of the Authority and not commingled with funds of any Party or any other
person or entity.
6.2.2 All funds of the Authority shall be strictly and separately accounted for,
and regular reports shall be rendered of all receipts and disbursements, at
least quarterly during the fiscal year. The books and records of the
Authority shall be open to inspection by the Parties at all reasonable times.
The Board shall contract with a certified public accountant or public
accountant to make an annual audit of the accounts and records of the
Authority, which shall be conducted in accordance with the requirements
of Section 6505 of the Act.
6.2.3 All expenditures shall be made in accordance with the approved budget
and upon the approval of any officer so authorized by the Board in
accordance with its Operating Rules and Regulations. The Treasurer shall
draw checks or warrants or make payments by other means for claims or
disbursements not within an applicable budget only upon the prior
approval of the Board.
6.3 Budget and Recovery Costs.
6.3.1 Budget. The initial budget shall be approved by the Board. The Board
may revise the budget from time to time through an Authority Document
as may be reasonably necessary to address contingencies and unexpected
expenses. All subsequent budgets of the Authority shall be prepared and
approved by the Board in accordance with the Operating Rules and
Regulations.
6.3.2 Funding of Initial Costs. The Initial Participants shall fund the Initial
Costs of the Authority in establishing the Authority and implementing the
CCA Program as described in Exhibit E to this Agreement. The Initial
Participants shall remit to the Authority their respective shares of Phase 2
and 3 Initial Costs as described in Exhibit E within 30 days after the
Effective Date. In the event that the CCA Program becomes operational,
these Initial Costs paid by the Initial Participants shall be included in the
customer charges for electric services as provided by Section 6.3.3 to the
extent permitted by law, and the Initial Participants shall be reimbursed by
the Authority within four years of the Effective Date. The Authority may
establish a reasonable time period over which such costs are recovered. In
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the event that the CCA Program does not become operational, the Initial
Participants shall not be entitled to any reimbursement of the Initial Costs
they have paid from the Authority or any Party.
6.3.3 CCA Program Costs. The Parties desire that, to the extent reasonably
practicable, all costs incurred by the Authority that are directly or
indirectly attributable to the provision of electric, conservation and energy
efficiency services under the CCA Program shall be recovered through
charges to CCA customers receiving such electric services or from
revenues received from grants or other third-party sources.
6.3.4 Additional Contributions and Advances. Pursuant to Government Code
Section 6504, the Parties may in their discretion make financial
contributions, loans or advances to the Authority for the purposes of the
Authority set forth in this Agreement. The repayment of such
contributions, loans or advances will be on the written terms agreed to by
the Party making the contribution, loan or advance and the Authority.
6.4 Debt. The Authority shall not incur any debts, including but not limited to loans
and the issuance of bonds, unless approved by a two-thirds affirmative vote of the entire Board
satisfying the requirements described in Section 4.9.
ARTICLE 7
WITHDRAWAL AND TERMINATION
7.1 Withdrawal.
7.1.1 General Right to Withdraw. A Party may withdraw its membership in
the Authority, effective as of the beginning of the Authority’s fiscal year,
by giving no less than 180 days advance written notice of its election to do
so, which notice shall be given to the Authority and each Party. By a two-
thirds affirmative vote of the entire Board satisfying the requirements
described in Section 4.9, the Board may shorten the 180 day period for a
withdrawal under this Section 7.1.1 to become effective.
7.1.2 Amendment. Notwithstanding Section 7.1.1, a Party may withdraw its
membership in the Authority following an amendment to this Agreement
provided that the requirements of this Section 7.1.2 are strictly followed.
A Party shall be deemed to have withdrawn its membership in the
Authority effective 180 days after the Board approves an amendment to
this Agreement if the Director representing such Party has provided notice
to the other Directors immediately preceding the Board’s vote of the
Party’s intention to withdraw its membership in the Authority should the
amendment be approved by the Board. By a two-thirds affirmative vote
of the entire Board satisfying the requirements described in Section 4.9,
the Board may shorten the 180 day period for a withdrawal under this
Section 7.1.2 to become effective.
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7.1.3 Liabilities; Further Assurances. A Party that withdraws its membership
in the Authority under either Section 7.1.1 or 7.1.2 may be subject to
certain liabilities, as described in Section 7.3. The withdrawing Party and
the Authority shall execute and deliver all further instruments and
documents, and take any further action that may be reasonably necessary,
as determined by the Board, to effectuate the orderly withdrawal of such
Party from membership in the Authority. The Operating Rules and
Regulations shall prescribe the rights, if any, of a withdrawn Party to
continue to participate in those Board discussions and decisions affecting
customers of the CCA Program that reside or do business within the
jurisdiction of the Party.
7.2 Involuntary Termination of a Party. This Agreement may be terminated with
respect to a Party for material non-compliance with provisions of this Agreement or the
Authority Documents upon a two-thirds affirmative vote of the entire Board satisfying the
requirements described in Section 4.9, including the vote and voting shares of the Party subject
to possible termination. Prior to any vote to terminate this Agreement with respect to a Party,
written notice of the proposed termination and the reason(s) for such termination shall be
delivered to the Party whose termination is proposed at least 30 days prior to the regular Board
meeting at which such matter shall first be discussed as an agenda item. The written notice of
proposed termination shall specify the particular provisions of this Agreement or the Authority
Documents that the Party has allegedly violated. The Party subject to possible termination shall
have the opportunity at the next regular Board meeting to respond to any reasons and allegations
that may be cited as a basis for termination prior to a vote regarding termination. A Party that has
had its membership in the Authority terminated may be subject to certain liabilities, as described
in Section 7.3.
7.3 Continuing Liability; Refund. Subject to the provisions of Section 2.3, upon a
withdrawal or involuntary termination of a Party pursuant to Sections 7.1 or 7.2, the Party shall
remain responsible for any claims, demands, damages, or liabilities arising from the Party’s
membership in the Authority through the date of its withdrawal or involuntary termination.
Notwithstanding Section 2.3,thereafter, the withdrawing or terminated Party shall be responsible
for any damages, losses or costs incurred by the Authority resulting from the Party’s withdrawal,
including but not limited to losses from the resale of power contracted for by the Authority to
serve the Party’s load. In addition, such Party also shall be responsible for any costs or
obligations associated with the Party’s participation in any program in accordance with the
provisions of any agreements relating to such program provided such costs or obligations were
incurred prior to the withdrawal of the Party. The Authority may withhold funds otherwise
owing to the Party or may require the Party to deposit sufficient funds with the Authority, as
reasonably determined by the Authority, to cover the Party’s liability for the costs described
above. Any amount of the Party’s funds held on deposit with the Authority above that which is
required to pay any liabilities or obligations shall be returned to the Party.
7.4 The Right to Withdraw Prior to Program Launch. After receiving bids from
power suppliers for the CCA Program, the Authority must provide to the Parties a report from
the electrical utility consultant retained by the Authority comparing the Authority’s total
estimated electrical rates, the estimated greenhouse gas emissions rate and the amount of
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estimated renewable energy to be used with that of the incumbent utility. Within 15 days after
receiving this report, any Party may immediately withdraw its membership in the Authority by
providing written notice of withdrawal to the Authority if the report determines that any one of
the following conditions exists: (1) the Authority is unable to provide total electrical rates, as
part of its baseline offering to customers, that are equal to or lower than the incumbent utility, (2)
the Authority is unable to provide electricity in a manner that has a lower greenhouse gas
emissions rate than the incumbent utility, or (3) the Authority will use less renewable energy
than the incumbent utility. Any Party who withdraws from the Authority pursuant to this Section
7.4 shall not be entitled to any refund of the Initial Costs it has paid to the Authority prior to the
date of withdrawal unless the Authority is later terminated pursuant to Section 7.5. In such
event, any Initial Costs not expended by the Authority shall be returned to all Parties, including
any Party that has withdrawn pursuant to this section, in proportion to the contribution that each
made. Notwithstanding anything to the contrary in this Agreement, any Party who withdraws
pursuant to this section shall not be responsible for any liabilities or obligations of the Authority
after the date of withdrawal, including without limitation any liability arising from power
purchase agreements entered into by the Authority.
7.5 Mutual Termination. This Agreement may be terminated by mutual agreement
of all the Parties; provided, however, the foregoing shall not be construed as limiting the rights of
a Party to withdraw its membership in the Authority, and thus terminate this Agreement with
respect to such withdrawing Party, as described in Section 7.1.
7.6 Disposition of Property upon Termination of Authority. Upon termination of
this Agreement as to all Parties, any surplus money or assets in possession of the Authority for
use under this Agreement, after payment of all liabilities, costs, expenses, and charges incurred
under this Agreement and under any Authority Documents, shall be returned to the then-existing
Parties in proportion to the contributions made by each.
ARTICLE 8
MISCELLANEOUS PROVISIONS
8.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts
to settle all disputes arising out of or in connection with this Agreement. Before exercising any
remedy provided by law, a Party or the Parties and the Authority shall engage in nonbinding
mediation or arbitration in the manner agreed upon by the Party or Parties and the Authority. In
the event that nonbinding mediation or arbitration is not initiated or does not result in the
settlement of a dispute within 120 days after the demand for mediation or arbitration is made,
any Party and the Authority may pursue any remedies provided by law.
8.2 Liability of Directors, Officers, and Employees. The Directors, officers, and
employees of the Authority shall use ordinary care and reasonable diligence in the exercise of
their powers and in the performance of their duties pursuant to this Agreement. No current or
former Director, officer, or employee will be responsible for any act or omission by another
Director, officer, or employee. The Authority shall defend, indemnify and hold harmless the
individual current and former Directors, officers, and employees for any acts or omissions in the
scope of their employment or duties in the manner provided by Government Code Section 995 et
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seq. Nothing in this section shall be construed to limit the defenses available under the law, to
the Parties, the Authority, or its Directors, officers, or employees.
8.3 Indemnification of Parties. The Authority shall acquire such insurance coverage
as the Board deems necessary to protect the interests of the Authority, the Parties and the public
but shall obtain no less than $2 million dollars in coverage. Such insurance coverage shall name
the Parties and their respective Board or Council members, officers, agents and employees as
additional insureds. The Authority shall defend, indemnify and hold harmless the Parties and
each of their respective Board or Council members, officers, agents and employees, from any
and all claims, losses, damages, costs, injuries and liabilities of every kind arising directly or
indirectly from the conduct, activities, operations, acts, and omissions of the Authority under this
Agreement.
8.4 Amendment of this Agreement. This Agreement may be amended in writing by
a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section
4.9. The Authority shall provide written notice to the Parties at least 30 days in advance of any
proposed amendment being considered by the Board. If the proposed amendment is adopted by
the Board, the Authority shall provide prompt written notice to all Parties of the effective date of
such amendment along with a copy of the amendment.
8.5 Assignment. Except as otherwise expressly provided in this Agreement, the rights
and duties of the Parties may not be assigned or delegated without the advance written consent of
all of the other Parties, and any attempt to assign or delegate such rights or duties in
contravention of this Section 8.5 shall be null and void. This Agreement shall inure to the benefit
of, and be binding upon, the successors and assigns of the Parties. This Section 8.5 does not
prohibit a Party from entering into an independent agreement with another agency, person, or
entity regarding the financing of that Party’s contributions to the Authority, or the disposition of
proceeds which that Party receives under this Agreement, so long as such independent agreement
does not affect, or purport to affect, the rights and duties of the Authority or the Parties under this
Agreement.
8.6 Severability. If one or more clauses, sentences, paragraphs or provisions of this
Agreement shall be held to be unlawful, invalid or unenforceable, it is hereby agreed by the
Parties, that the remainder of the Agreement shall not be affected thereby. Such clauses,
sentences, paragraphs or provision shall be deemed reformed so as to be lawful, valid and
enforced to the maximum extent possible.
8.7 Further Assurances. Each Party agrees to execute and deliver all further
instruments and documents, and take any further action that may be reasonably necessary, to
effectuate the purposes and intent of this Agreement.
8.8 Execution by Counterparts. This Agreement may be executed in any number of
counterparts, and upon execution by all Parties, each executed counterpart shall have the same
force and effect as an original instrument and as if all Parties had signed the same instrument.
Any signature page of this Agreement may be detached from any counterpart of this Agreement
without impairing the legal effect of any signatures thereon, and may be attached to another
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counterpart of this Agreement identical in form hereto but having attached to it one or more
signature pages.
8.9 Parties to be Served Notice. Any notice authorized or required to be given
pursuant to this Agreement shall be validly given if served in writing either personally, by
deposit in the United States mail, first class postage prepaid with return receipt requested, or by a
recognized courier service. Notices given (a) personally or by courier service shall be
conclusively deemed received at the time of delivery and receipt and (b) by mail shall be
conclusively deemed given 72 hours after the deposit thereof (excluding Saturdays, Sundays and
holidays) if the sender receives the return receipt. All notices shall be addressed to the office of
the clerk or secretary of the Authority or Party, as the case may be, or such other person
designated in writing by the Authority or Party. In addition, a duplicate copy of all notices
provided pursuant to this section shall be provided to the Director and Alternate Director for
each Party. Notices given to one Party shall be copied to all other Parties. Notices given to the
Authority shall be copied to all Parties.
ARTICLE 9
SIGNATURE
IN WITNESS WHEREOF, the Parties hereto have executed this Joint Powers Agreement
establishing the Silicon Valley Clean Energy Authority.
By:
Name:
Title:
Date:
Party:
284
Exhibit A
Page 1
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EXHIBIT A
-DEFINITIONS-
“AB 117” means Assembly Bill 117 (Stat. 2002, ch. 838, codified at Public Utilities Code
Section 366.2), which created CCA.
“Act” means the Joint Exercise of Powers Act of the State of California (Government Code
Section 6500 et seq.)
“Agreement” means this Joint Powers Agreement.
“Annual Energy Use” has the meaning given in Section 4.9.2.
“Authority” means the Silicon Valley Clean Energy Authority.
“Authority Document(s)” means document(s) duly adopted by the Board by resolution or motion
implementing the powers, functions and activities of the Authority, including but not limited to
the Operating Rules and Regulations, the annual budget, and plans and policies.
“Board” means the Board of Directors of the Authority.
“CCA” or “Community Choice Aggregation” means an electric service option available to cities
and counties pursuant to Public Utilities Code Section 366.2.
“CCA Program” means the Authority’s program relating to CCA that is principally described in
Sections 2.4 and 5.1.
“Days” shall mean calendar days unless otherwise specified by this Agreement.
“Director” means a member of the Board of Directors representing a Party.
“Effective Date” means the date on which this Agreement shall become effective and the Silicon
Valley Clean Energy Authority shall exist as a separate public agency, as further described in
Section 2.1.
“Implementation Plan” means the plan generally described in Section 5.1.2 of this Agreement
that is required under Public Utilities Code Section 366.2 to be filed with the California Public
Utilities Commission for the purpose of describing a proposed CCA Program.
“Initial Costs” means all costs incurred by the Authority relating to the establishment and initial
operation of the Authority, such as the hiring of an Executive Director and any administrative
staff, any required accounting, administrative, technical and legal services in support of the
Authority’s initial activities or in support of the negotiation, preparation and approval of power
purchase agreements. The Board shall determine the termination date for Initial Costs.
“Initial Participants” means, for the purpose of this Agreement the County of Santa Clara, the
Cities of Campbell, Cupertino, Gilroy, Los Altos, Monte Sereno, Morgan Hill, Mountain View,
Saratoga, and Sunnyvale, and the Towns of Los Altos and Los Gatos.
285
Exhibit A
Page 2
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“Operating Rules and Regulations” means the rules, regulations, policies, bylaws and procedures
governing the operation of the Authority.
“Parties” means, collectively, the signatories to this Agreement that have satisfied the conditions
in Sections 2.2 or 3.1 such that it is considered a member of the Authority.
“Party” means, singularly, a signatory to this Agreement that has satisfied the conditions in
Sections 2.2 or 3.1 such that it is considered a member of the Authority.
“Percentage vote” means a vote taken by the Board pursuant to Section 4.9.1 that is based on
each Party having one equal vote.
“Total Annual Energy” has the meaning given in Section 4.9.2.
“Voting shares vote” means a vote taken by the Board pursuant to Section 4.9.2 that is based on
the voting shares of each Party described in Section 4.9.3 and set forth in Exhibit D to this
Agreement. A voting shares vote cannot take place on a matter unless the matter first receives an
affirmative percentage vote in the manner required by Section 4.9.1 and two or more Directors
immediately thereafter request such vote.
286
Exhibit B
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DRAFT EXHIBIT B
-LIST OF THE PARTIES
(This draft exhibit is based on the assumption that all of the Initial Participants will
become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to
this Agreement at that time.)-
City of Campbell
City of Cupertino
City of Gilroy
City of Los Altos
Town of Los Altos Hills
Town of Los Gatos
City of Monte Sereno
City of Morgan Hill
City of Mountain View
County of Santa Clara (Unincorporated Area)
City of Saratoga
City of Sunnyvale
287
Exhibit C
Page 1
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DRAFT EXHIBIT C
-ANNUAL ENERGY USE
(This draft exhibit is based on the assumption that all of the Initial Participants will
become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to
this Agreement at that time.)
This Exhibit C is effective as of March 31, 2016.
Party kWh (2014*)
Campbell 208,827
Cupertino 243,360
Gilroy 296,993
Los Altos 142,219
Los Altos Hills 42,577
Los Gatos 196,007
Monte Sereno 7,939
Morgan Hill 232,521
Mountain View 664,209
Santa Clara County
(Unincorporated)
397,902
Saratoga 131,604
Sunnyvale 1,407,826
*Data provided by PG&E
288
Exhibit D
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10016-003\1901335v1.doc
DRAFT EXHIBIT D
- VOTING SHARES
(This draft exhibit is based on the assumption that all of the Initial Participants will
become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to
this Agreement at that time.)
This Exhibit D is effective as of March 31. 2016.
Party kWh (2014*) Voting Share
Section 4.9.2
Campbell 208,827 5.3%
Cupertino 243,360 6.1%
Gilroy 296,993 7.5%
Los Altos 142,219 3.6%
Los Altos Hills 42,577 1.1%
Los Gatos 196,007 4.9%
Monte Sereno 7,939 0.2%
Morgan Hill 232,521 5.9%
Mountain View 664,209 16.7%
Santa Clara County
(Unincorporated)
397,902 10.0%
Saratoga 131,604 3.3%
Sunnyvale 1,407,826 35.4%
Total 3,971,985 100.0%
*Data provided by PG&E
289
Exhibit E
Page 1
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DRAFT EXHIBIT E
- FUNDING OF INITIAL COSTS
- (This draft exhibit is based on the assumption that all of the Initial Participants will
become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties
to this Agreement at that time.)
Party Phase 1(*) Phase 2 and 3 (**) Phase 2 & 3
w/Contingency (***)
Campbell -- $100,000 $150,000
Cupertino $170,000 $350,000 $450,000
Gilroy -- $100,000 $150,000
Los Altos -- $100,000 $150,000
Los Altos Hills -- $25,000 $25,000
Los Gatos -- $100,000 $150,000
Monte Sereno -- $25,000 $25,000
Morgan Hill -- $100,000 $150,000
Mountain View $170,000 $350,000 $450,000
Santa Clara County
(Unincorporated)
$170,000 $350,000 $450,000
Saratoga -- $100,000 $150,000
Sunnyvale $170,000 $350,000 $450,000
Total $680,000 $2,050,000 N/A
- (*) Certain Parties have contributed funding prior to the Effective Date of this Agreement, as
shown above under Phase 1, to conduct initial legal, technical, and administrative activities in
support of the establishment of the Authority. Such activities are part of the Initial Costs
described in Section 6.3 of this Agreement.
- (**) Additional costs associated with program launch will be financed and thus are not
covered by the Initial Cost Contributions shown here.
- (***) Initial Participants are required to commit up to this amount at the time of executing
the Agreement; this amount includes contingency funding should multiple Initial Participants
not execute the Agreement by 3/31/16, so that the final Parties are providing sufficient
contribution for Initial Costs. The Parties will be notified promptly after the Effective Date
of the final Parties and contribution to Initial Costs
290
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