HomeMy WebLinkAboutBOARD STANDING COMMITTEES - 12122016 - Internal Ops Cte Min
INTERNAL OPERATIONS
COMMITTEE
December 12, 2016
11:00 A.M.
Note Location Change: 651 Pine Street,
Room 107, Martinez
Supervisor John Gioia, Chair
Supervisor Candace Andersen, Vice Chair
Agenda
Items:
Items may be taken out of order based on the business of the day and preference
of the Committee
1.Introductions
2.Public comment on any item under the jurisdiction of the Committee and not on this
agenda (speakers may be limited to three minutes).
3. RECEIVE and APPROVE the Record of Action for the October 24, 2016 IOC meeting.
(Julie DiMaggio Enea, IOC Staff)
4. INTERVIEW candidates for the At Large #3 and #4 seats on the Fish and Wildlife
Committee for four-year terms ending on December 31, 2020, and DETERMINE
recommendations for Board of Supervisors consideration. (Maureen Parkes,
Conservation and Development Department)
5. INTERVIEW candidates for one vacancy on the Contra Costa Resource Conservation
District Board of Directors and DETERMINE recommendation for Board of
Supervisors consideration. (Julie DiMaggio Enea, County Administrator's Office)
6. INTERVIEW candidates for two At Large seats on the Aviation Advisory Committee
and DETERMINE recommendations for Board of Supervisors consideration. (Keith
Freitas, Airports Director)
7. CONSIDER recommending the reappointment of incumbent Nolan Armstrong to the
Member of the Bar seat on the Contra Costa County Law Library Board of Trustees.
(Julie DiMaggio Enea, County Administrator's Office)
8. CONSIDER recommending the reappointment of incumbents Chris Cowen to the At
Large #2 seat and Darryl Young to the At Large #3 seat on the Contra Costa Mosquito
& Vector Control District Board of Trustees to new four-year terms ending on January
2, 2021. (Julie DiMaggio Enea, County Administrator's Office)
9. REVIEW draft technical study of Community Choice Energy options for possible
implementation by the County and participating cities. (Jason Crapo, Conservation
and Development Department)
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10. CONSIDER a draft ordinance to authorize administrative penalties for animal noise
violations and to prohibit the harboring of more than four roosters on private property.
(Beth Ward, Animal Services Director)
11. REVIEW the Committee's work for 2016 and identify issues to be referred to the 2017
Internal Operations Committee. (Julie DiMaggio Enea, County Administrator's Office)
12.Adjourn
The 2016 Internal Operations Committee has no additional meetings scheduled this year.
The Internal Operations Committee will provide reasonable accommodations for persons with
disabilities planning to attend Internal Operations Committee meetings. Contact the staff person
listed below at least 72 hours before the meeting.
Any disclosable public records related to an open session item on a regular meeting agenda and
distributed by the County to a majority of members of the Internal Operations Committee less than
96 hours prior to that meeting are available for public inspection at 651 Pine Street, 10th floor,
during normal business hours. Staff reports related to items on the agenda are also accessible on
line at www.co.contra-costa.ca.us.
Public comment may be submitted via electronic mail on agenda items at least one full work day
prior to the published meeting time.
For Additional Information Contact:
Julie DiMaggio Enea, Committee Staff
Phone (925) 335-1077, Fax (925) 646-1353
julie.enea@cao.cccounty.us
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INTERNAL OPERATIONS
COMMITTEE-SPECIAL MEETING 3.
Meeting Date:12/12/2016
Subject:RECORD OF ACTION FOR THE OCTOBER 24, 2016 IOC MEETING
Submitted For: David Twa, County Administrator
Department:County Administrator
Referral No.: N/A
Referral Name: RECORD OF ACTION
Presenter: Julie DiMaggio Enea, IOC Staff Contact: Julie DiMaggio Enea (925)
335-1077
Referral History:
County Ordinance requires that each County body keep a record of its meetings. Though the
record need not be verbatim, it must accurately reflect the agenda and the decisions made in the
meeting.
Referral Update:
Attached is the Record of Action for the October 24, 2016 IOC meeting.
Recommendation(s)/Next Step(s):
RECEIVE and APPROVE the Record of Action for the October 24, 2016 IOC meeting.
Fiscal Impact (if any):
None.
Attachments
DRAFT Record of Action for 10-24-16 IOC Meeting
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D R A F T
INTERNAL OPERATIONS
COMMITTEE
RECORD OF ACTION FOR
October 24, 2016
11:00 A.M.
Supervisor John Gioia, Chair
Supervisor Candace Andersen, Vice Chair
Present: John Gioia, Chair
Candace Andersen, Vice Chair
Staff Present:Julie DiMaggio Enea, Staff
Attendees: Allison Picard, Chief Asst CAO
Jami Napier, Sr Deputy CAO, Clerk of the Board
David Gould, County Purchasing Services
Manager
CeCe Selgren
1.Introductions
Chair Gioia convened the meeting at 11:00 a.m.. Self-introductions were made
around the room.
2.Public comment on any item under the jurisdiction of the Committee and not on this
agenda (speakers may be limited to three minutes).
No members of the public asked to speak during the Public Comment period.
3.RECEIVE and APPROVE the Record of Action for the September 26, 2016 IOC
meeting.
The Record of Action for the September 26, 2016 meeting was approved as
presented.
AYE: Chair John Gioia, Vice Chair Candace Andersen
Passed
4.INTERVIEW candidates for the Contra Costa Resource Conservation District Board of
Directors, and DETERMINE recommendations for appointment to three seats with
terms ending on November 30, 2020.
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None of the four candidates attended the meeting. Staff advised the Committee that
candidates Igor Skaredoff and Tom Brumleve were unable to attend due to prior
commitments.
CeCe Selgren spoke in favor of reappointing Igor Skaredoff and Tom Brumleve. The
Committee decided to recommend their reappointment and directed staff to obtain
the attendance records of the candidates, and invite the remaining candidates Bob
Case and Jency James to the December 12 IOC meeting for further consideration.
AYE: Chair John Gioia, Vice Chair Candace Andersen
Passed
5.ACCEPT the Small Business Enterprise and Outreach Report covering the period
January - December 2015 and CONSIDER staff recommendations on the Small
Business Enterprise Program.
Allison Picard presented the Small Business Enterprise and Outreach Program
reports covering the period January 1, 2015 through June 30, 2016. The Committee
accepted the report and findings, directed staff to forward the report to the Board of
Supervisors on Consent, and requested the Purchasing Services Manager to return
with a follow-up report in February 2017 showing the top 50-100 commodities less
than $100,000 purchased by the County.
AYE: Chair John Gioia, Vice Chair Candace Andersen
Passed
6.The next meeting is currently scheduled for November 28, 2016.
The Committee decided cancel the November 28, 2016 meeting due to a schedule
conflict with the CSAC Conference, and scheduled a special meeting for December
12, 2016 at 11:00 a.m.
AYE: Chair John Gioia, Vice Chair Candace Andersen
Passed
7.Adjourn
Chair Gioia adjourned the meeting at 11:20 a.m.
For Additional Information Contact:
Julie DiMaggio Enea, Committee Staff
Phone (925) 335-1077, Fax (925) 646-1353
julie.enea@cao.cccounty.us
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INTERNAL OPERATIONS COMMITTEE-SPECIAL
MEETING 4.
Meeting Date:12/12/2016
Subject:FISH & WILDLIFE COMMITTEE RECRUITMENT
Submitted For: John Kopchik, Interim Director, Conservation & Development
Department
Department:Conservation & Development
Referral No.: IOC 16/5
Referral Name: ADVISORY BODY RECRUITMENT
Presenter: Maureen Parkes Contact: Maureen Parkes
925-674-7831
Referral History:
Per IOC policy, the IOC conduct interviews for At Large seats on the following bodies:
Retirement Board, Fire Advisory Commission, Integrated Pest Management Advisory
Committee, Planning Commission, Treasury Oversight Board, Airport Land Use Commission,
Aviation Advisory Committee and the Fish & Wildlife Committee; and delegates the screening
and nomination fill At Large seats on all other eligible bodies to each body or a subcommittee
thereof.
Referral Update:
The Fish & Wildlife Committee was established by the Board in December 1994 to advise the
Board on fish and wildlife issues, make recommendations for the expenditure of funds from the
Fish and Wildlife Propagation Fund, and to address issues surrounding the enforcement of fish
and game laws and regulations of the County. The Committee comprises ten members: one
nominated by each County Supervisor, four At Large seats, and one At Large Alternate seat. Seat
terms are two years. The IOC conducts interviews for the At Large and At Large Alternate seats.
On December 31, 2016, the terms for the At Large #3 and #4 seats will expire. The Conservation
& Development Department recruited for applicants as described in the attached transmittal
memo. Six applications were received and are attached hereto along with a report from the Fish &
Wildlife Committee staff.
Recommendation(s)/Next Step(s):
INTERVIEW the following candidates for the At Large #3 and #4 seats for four-year terms
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INTERVIEW the following candidates for the At Large #3 and #4 seats for four-year terms
ending on December 31, 2020, and DETERMINE recommendations for Board of Supervisors
consideration:
Scott Cashen (Walnut Creek)
Edmond Linscheid (Orinda)
Joshua Porter (Kensington)
Heather Rosmarin (Pleasant Hill)
Jeffrey Skinner, incumbent (Martinez)
Rodney Smith (Danville)
Fiscal Impact (if any):
None.
Attachments
F&W Cte Staff Report and Candidate Applications
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12/5/2016
FISH AND WILDLIFE COMMITTEE ROSTER
Appointment Date Term Expires
Vacant (District 1)
Susan Heckly (District II)
Pleasant Hill
April 14, 2015 February 28, 2018
Clark Dawson (District III)
Antioch
March 31, 2015
February 28, 2018
Brett Morris (District IV)
Walnut Creek
March 3, 2015
February 28, 2019
Daniel Pellegrini (District V)
Martinez
March 3, 2015 February 28, 2019
Roni Gehlke (At-Large 1)
Oakley
January 5, 2016
December 31, 2018
Kathleen Jennings (At-Large 2)
Concord
January 5, 2016
December 31, 2018
Jeff Skinner(At-Large 3)
Martinez
December 9, 2014 December 31, 2016
Scott Stephan (At-Large 4)
San Ramon
December 9, 2014 December 31, 2016
Dawn Manley (At-Large Alternate 1)
Walnut Creek
September 13, 2016
January 1, 2017
December 31, 2016
December 31, 2021
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INTERNAL OPERATIONS
COMMITTEE-SPECIAL MEETING 5.
Meeting Date:12/12/2016
Subject:INTERVIEW CANDIDATES FOR ONE VACANCY ON THE
CONTRA COSTA RESOURCE CONSERVATION DISTRICT BOARD
OF DIRECTORS
Submitted For: David Twa, County Administrator
Department:County Administrator
Referral No.: IOC 16/5
Referral Name: Advisory Body Recruitment
Presenter: Julie DiMaggio Enea Contact: Julie DiMaggio Enea (925)
335-1077
Referral History:
Contra Costa Resource Conservation District (RCD) director recruitment is conducted by the
County pursuant to a 1998 RCD resolution ordering that all future directors shall be appointed by
the County Board of Supervisors in lieu of election (Public Resources Code Section 9314).
The mission of the RCD is to carry out natural resources conservation projects through voluntary
and cooperative efforts. The RCD is a non-regulatory agency that works with individuals,
growers, ranchers, public agencies, non-profit organizations and corporations to accomplish its
mission. The USDA Natural Resource Conservation Service provides technical support for the
RCD's programs.
Referral Update:
On November 30, 2016, the terms of office for three of the five RCD Director seats will expired:
President, Director 1, and Director 3. Following a five-week recruitment that garnered four
applications, the IOC, on October 24, decided to recommend the reappointment of incumbents
Tom Brumleve and Igor Skaredoff, and directed staff to obtain the attendance records of the
candidates and invite the remaining candidates Bob Case and Jency James to the December 12
IOC meeting for further consideration.
Consequently, the current sitting RCD members are:
Igor Skaredoff (Martinez)
Tom Brumleve (Walnut Creek)
Bethallyn Black (Walnut Creek)
Tom Bloomfield (Brentwood)
One Director seat remains vacant. Terms of office are four years beginning on December 1.
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Recommendation(s)/Next Step(s):
INTERVIEW the following candidates for one vacancy on the Contra Costa Resource
Conservation District Board of Directors and DETERMINE recommendation for Board of
Supervisors consideration:
Bob Case, incumbent (Concord)
Jency James (Martinez)
Attachments
Candidate Application_Bob Case_CCRCD
Candidate Application_Jency James_CCRCD
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INTERNAL OPERATIONS COMMITTEE-SPECIAL
MEETING 6.
Meeting Date:12/12/2016
Subject:NOMINATIONS TO THE AVIATION ADVISORY
COMMITTEE
Submitted For: Keith Freitas, Airports Director
Department:Airports
Referral No.: IOC 16/5
Referral Name: Advisory Body Recruitment
Presenter: Keith Freitas Contact: Judith Evans (925)
681-4200
Referral History:
The Aviation Advisory Committee was established by the Board of Supervisors in 1977. It's
current charge is to provide advice and recommendations to the Board of Supervisors on the
aviation issues related to the economic viability and security of airports in Contra Costa County.
The Committee may initiate discussions, observations, or investigations, in order to make its
recommendations to the Board. The Committee may hear comments on airport and aviation
matters from the public or other agencies for consideration and possible recommendations to the
Board of Supervisors or their designees. The Aviation Advisory Committee shall cooperate with
local, state, and national aviation interests for the safe and orderly operation of airports. The
Aviation Advisory Committee shall advance and promote the interests of aviation and protect the
general welfare of the people living and working near the airport and the County in general. In
conjunction with all of the above, the Aviation Advisory Committee shall provide a forum for the
Director of Airports regarding policy matters at and around the airports.
Referral Update:
In March 1, 2017, the At Large 2 seat term of office will expire. Additionally, the former Diablo
Valley College seat was converted to an At Large seat and is currently vacant. The Airports
Director opened a four-week recruitment on October 27, 2016 to fill the current and pending
vacancies, garnering four applications, attached. All candidates were invited to the IOC meeting
today to be interviewed, as per the IOC's policy.
Seat terms are three years. The term for the next At Large 2 appointment will be March 2,
2017-March 1, 2020. The current term for the At Large 3 (formerly DVC) seat will expire on
March 1, 2019.
Recommendation(s)/Next Step(s):
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INTERVIEW the following candidates for two At Large seats on the Aviation Advisory
Committee and DETERMINE recommendations for Board of Supervisors consideration:
Emily Barnett, Pleasant Hill
Christopher Hansen, Concord
DeWitt Hodge (incumbent), Pittsburg
Geoffrey Logan, Walnut Creek
Fiscal Impact (if any):
None. AAC members are not compensated.
Attachments
Airports Director Transmittal Memo
Candidate Application_AAC_Emily Barnett
Candidate Application_AAC_Christopher Hansen
Candidate Application_AAC_DeWitt Hodge
Candidate Application_AAC_Geoffrey Logan
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INTERNAL OPERATIONS
COMMITTEE-SPECIAL MEETING 7.
Meeting Date:12/12/2016
Subject:NOMINATION TO THE CONTRA COSTA COUNTY LAW
LIBRARY BOARD OF TRUSTEES
Submitted For: David Twa, County Administrator
Department:County Administrator
Referral No.: IOC 16/5
Referral Name: Advisory Body Recruitment
Presenter: Julie DiMaggio Enea Contact: Julie DiMaggio Enea (925)
335-1077
Referral History:
The Public Law Library Board of Trustees was established by State law and County Ordinance to
maintain a law library in Martinez and a branch library in Richmond. The Board of Trustees is the
governing body for the Law Library with the authority to determine personnel, fiscal, and
administrative policies to fulfill the legal information needs of the community. The Internal
Operations Committee annually reviews the appointment to the Member of the Bar seat, which
term expires each December 31.
Referral Update:
The IO Committee is asked to consider re-appointing Nolan Armstrong to the Member of the Bar
seat to a new one-year term expiring December 31, 2017. The Law Librarian recruited for the seat
and received interest only from Mr. Armstrong, who wishes to be reappointed.
Recommendation(s)/Next Step(s):
APPROVE recommendation to re-appoint Nolan Armstrong to the Member of the Bar seat on the
Law Library Board of Trustees to a new one-year term expiring December 31, 2017.
Fiscal Impact (if any):
None.
Attachments
Letter of Interest_Nolan Armstrong_Law Library
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INTERNAL OPERATIONS
COMMITTEE-SPECIAL MEETING 8.
Meeting Date:12/12/2016
Subject:NOMINATION TO THE MOSQUITO & VECTOR CONTROL
DISTRICT BOARD OF TRUSTEES
Submitted For: David Twa, County Administrator
Department:County Administrator
Referral No.: IOC 16/5
Referral Name: ADVISORY BODY RECRUITMENT
Presenter: Julie Enea Contact: Allison Nelson
925-685-9301
Referral History:
The Contra Costa Mosquito & Vector Control District was established in 1986 through the
consolidation of two such districts. The boundaries of the current District are all of Contra Costa
County. The District provides Countywide public health services through the control of
mosquitoes, rats, skunks, yellowjackets and other vectors. Of the 22 members of the Board of
Trustees, the Board of Supervisors appoints three to represent the unincorporated area. The
Internal Operations Committee (IOC) screens the nominations for the three County seats.
Referral Update:
On January 2, 2017, the terms of office of the At Large 2 and 3 seats will expire. New
appointments to the seats may be made for either two or four years, at the discretion of the Board
of Supervisors.
Staff initiated a four-week recruitment on October 3, 2016 that garnered two applications,
attached, from incumbents Chris Cowen and Darryl Young.
Recommendation(s)/Next Step(s):
CONSIDER recommending the reappointment of incumbents Chris Cowen (San Pablo) to the At
Large #2 seat and Darryl Young (XXX) to the At Large #3 seat on the Contra Costa Mosquito &
Vector Control District Board of Trustees to new four-year terms ending on January 2, 2021.
Attachments
MVCD Press Publication
Candidate Application_Chris Cowen_MVCD
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Contra Costa County
County Administrator’s Office • 651 Pine Street • Martinez, CA 94553 • www.co.contra-costa.ca.us
Media Release
FOR IMMEDIATE RELEASE Contact: Julie DiMaggio Enea
Monday, October 3, 2016 Phone: (925) 335-1077
Email: julie.enea@cao.cccounty.us
WOULD YOU LIKE TO SERVE ON THE
CONTRA COSTA MOSQUITO & VECTOR CONTROL DISTRICT
BOARD OF TRUSTEES ?
The Contra Costa Mosquito & Vector Control District was established in 1986. The
boundaries of the current District are all of Contra Costa County. The District provides
Countywide public health services through the control of mosquitoes, rats, skunks,
yellowjackets and other vectors. This is important to prevent the transmission of disease
and to minimize vector population outbreaks, which would interfere with recreational,
residential, agricultural, and industrial activities. The District Board of Trustees meets
on the second Monday of every other month at 7 p.m. in Concord.
The County is recruiting for volunteers to fill two vacancies for four-year terms ending on
January 2, 2021. The County Board of Supervisors will make the appointments.
County residents are encouraged to apply.
Application forms can be obtained from the Clerk of the Board of Supervisors by calling
(925) 335-1900 or by visiting the County webpage at www.co.contra-costa.ca.us.
Applications should be returned to the Clerk of the Board of Supervisors, Room 106,
County Administration Building, 651 Pine Street, Martinez, CA 94553 no later than
Friday, November 4, 2016 by 5 p.m. Applicants should plan to be available for public
interviews in Martinez on Monday, November 28. More information about the Contra
Costa Mosquito & Vector Control District can be obtained by visiting the District’s
website at http://www.contracostamosquito.com/ .
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INTERNAL OPERATIONS
COMMITTEE-SPECIAL MEETING 9.
Meeting Date:12/12/2016
Subject:REVIEW OF DRAFT TECHNICAL STUDY OF COMMUNITY
CHOICE ENERGY OPTIONS
Submitted For: Jason Crapo, County Building Official
Department:Conservation & Development
Referral No.: IOC 16/11
Referral Name: COMMUNITY CHOICE ENERGY
Presenter: Jason Crapo Contact: Jason Crapo, 925-674-7722
Referral History:
On March 15, 2016, the Board of Supervisors directed staff to work with interested cities in
Contra Costa County to obtain electrical load data from PG&E and conduct a technical study of
the following three CCE alternatives:
Form a new joint powers authority of the County and interested cities within Contra Costa
County for the purpose of implementing Community Choice Energy
Join Marin Clean Energy (MCE)
Form a new joint powers authority with Alameda County and the interested group of cities
in the two-county region
The Board directed County staff to request that each participating city contribute financially
towards the cost of the technical study in an amount proportional to the size of that city's
population.
During the spring of 2016, County staff negotiated a memorandum of understanding (MOU) with
the 14 cities within the County that are currently not members of a CCE program (five cities
within the County are members of the CCE program initiated in Marin County known as MCE
Clean Energy). On April 12, the Board approved a non-disclosure agreement with PG&E to
obtain electrical load data within Contra Costa County to inform the study; and on June 21, the
Board approved an MOU with participating cities to initiate a technical study. The MOU was
executed by 13 of the 14 cities named in the MOU (the City of Orinda did not execute the MOU).
Nine of the cities that are parties to the MOU are designated in the MOU as Funding Cities and
have agreed to contribute financially towards the cost of the technical study in an amount
proportional to their population size. As described in the MOU, these Funding Cities will
reimburse the County for their share of cost following completion of the technical study. The nine
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cities contributing financially towards the cost of the technical study are Brentwood, Clayton,
Concord, Danville, Martinez, Moraga, Pittsburg, Pleasant Hill and San Ramon. The 5 cities that
contributed data but decided to not contribute funding for the technical study are Antioch,
Hercules, Oakley, Orinda and Pinole.
MRW was selected as the consultant to perform the technical study through a competitive process
following the release of a Request for Proposals (RFP) that was administered by the County
Department of Conservation and Development and the County's Purchasing Division in the Public
Works Department. As specified in the MOU, responses to the RFP were reviewed by an
Evaluation Committee comprised of representatives from the County Department of
Conservation and Development, the County Administrator's Office, and the cities of Brentwood,
Danville and Pittsburg. The Evaluation Committee was unanimous in its selection of MRW as the
most qualified of the responsive firms to perform the technical study.
Following the selection of MRW by the Evaluation Committee, the County negotiated a contract
with MRW to perform the technical study. This contract was approved by the Board of
Supervisors on August 16, 2016.
Referral Update:
Attached is the draft of the CCE technical study and its findings (Attachment A).
Background
Community Choice Energy (CCE) is described in State law as Community Choice Aggregation.
CCE involves cities, counties, or a joint powers authority (JPA) comprised of cities and/or
counties, pooling ("aggregating") retail electricity customers for the purpose of procuring and
selling electricity. Under a CCE program, the CCE entity would become the default electricity
provider to all electricity customers within the service area. Costumers would have the ability to
opt out of service from the CCE program and return to service from the incumbent electrical
utility. In Contra Costa County, the incumbent electrical utility is Pacific Gas and Electric
(PG&E).
Following the launch of CCE programs in Marin County in 2010 and Sonoma County in 2014,
most other counties in the Bay Area and many counties throughout California are now in the
process of studying or implementing CCE programs. Napa County joined the CCE program
initiated in Marin County, MCE Clean Energy, in early 2016. The City and County of San
Francisco launched a CCE program in May 2016, and San Mateo County launched its program in
October 2016. Alameda County and Santa Clara County are both establishing JPAs for this
purpose, with the intent to launch programs in 2017.
Scope of the Technical Study
Consistent with direction County staff received from the Board of Supervisors when the Board
authorized the technical study on March 15, 2016, the scope of the technical study includes a
comparison of 3 different CCE program alternatives that could be implemented by participating
jurisdictions in Contra Costa County to the fourth option of remaining with existing service from
PG&E. The 3 CCE alternatives considered in the study are:
Form a new joint powers authority (JPA) of the County and interested cities within Contra
Costa County for the purpose of implementing Community Choice Energy;
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Join MCE Clean Energy (MCE) by seeking to become a members of its JPA;2.
Join the new JPA known as East Bay Community Energy (EBCE), along with Alameda
County and the interested group of cities in the two-county East Bay region, for the purpose
of CCE.
3.
The technical study analyzes electrical load data that the County has requested and obtained from
PG&E for the unincorporated area and the 14 participating cities. The technical study projects the
electricity rates that might be charged by a new CCE program in Contra Costa County to its
customers under several energy procurement scenarios and compares these projected rates to
PG&E’s projected rates. The study assesses the potential for a CCE program to lower greenhouse
gas emissions generated from energy use within the participating jurisdictions compared to
current PG&E service, and the extent to which a CCE program could stimulate economic activity
within the County through reduced electricity rates and construction of local renewable energy
generation facilities. Finally, the study includes a comparison among the 3 CCE program
alternatives considered and the option of continuing with existing PG&E service, and presents the
tradeoffs associated with each of these 4 options.
Main Findings of the Draft Technical Study
The main findings of the Draft Technical Study (found in its Executive Summary) are as follows:
Jurisdictions in Contra Costs County studied in the Draft Technical Study have several
options for implementing a Community Choice Energy (CCE) program that would likely
result in lower GHG emissions, increased local renewable energy generation, and increased
local job creation compared to remaining with current electricity service from the Pacific
Gas and Electric Company (PG&E).
1.
The electricity rates charged under various CCE scenarios available to the jurisdictions
covered in the Draft Technical Study would likely be similar or less than the rates charged
by PG&E for comparable service. The degree to which CCE rates are reduced below
comparable PG&E rates depends in large part on the extent to which the CCE pursues policy
objectives other that rate minimization in its energy procurement practices. Competing
policy objectives may include increasing the supply of locally generated renewable energy,
promoting energy efficiency, and maximizing local employment generated from a CCE
program.
2.
The Draft Technical Study finds that Contra Costa County includes enough technically
feasible locations to meet a significant proportion of electricity demand for the area studied
through locally generated renewable energy. Forty percent of the technically feasible sites
fall within the Northern Waterfront Economic Development Initiative area.
3.
The implementation of a CCE program within the studied area is projected to create between
500 and 1000 new jobs within Contra Costa County compared to remaining with current
PG&E service, depending on the CCE option implemented.
4.
The Draft Technical Study compares three CCE program alternatives to current PG&E
service and identifies the tradeoffs associated with these four alternatives. The decision of
which program alternative to implement will require policy makers to balance costs and
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potential risks and benefits of each option.
Recommendation(s)/Next Step(s):
Next Steps
The Draft Technical Study had been distributed to the participating cities and the general public
for comment. The comment period will close on January 31, 2017. Seven of the participating
cities have so far requested presentations of the Draft Technical Study at upcoming City Council
meetings in early 2017. Several community groups have also expressed interest in receiving
presentations of the Draft Study results.
Following conclusion of the comment period, County staff will work with MRW and Associates
to finalize the technical study in February 2017. The final technical study will then be presented to
the Board and the City Councils in March and April 2017 for further action, and potentially for
direction to implement one of the CCE options considered in the study.
Recommendations
Accept this report and direct staff to present the Draft Technical Study to the Board of
Supervisors and receive comments and direction from the Board at its meeting on January
17, 2017.
1.
Recommend to the Board of Supervisors that the Board direct DCD staff to request terms of
membership in EBCE from the EBCE Board of Directors on behalf of the County.
2.
Fiscal Impact (if any):
There is no fiscal impact associated with today's recommendations. Although financial
considerations were not the primary focus of the analysis, the Draft Technical Study briefly
describes the financial implications of the options evaluated. These financial implications are
summarized as follows:
Contra Costa JPA Option
Creating a new JPA of the County and cities solely within Contra Costa County for the purpose of
CCE would require the County and participating cities to identify a funding source to support
approximately $2 million in additional start-up costs and secure a source of credit, or “working
capital,” on the order of $20 million to bridge the new JPA to the point where it generates
sufficient revenue from customer electricity accounts to become self-supporting. Out-of-pocket
expenses incurred by these jurisdictions would be reimbursable by the newly created JPA.
The most likely source of funding for the estimated $2 million in additional start-up costs for a
Contra Costa JPA option would be a loan from the County to the JPA, which could be repaid to
the County by the JPA, potentially with interest, within the first year or two after the JPA is
established.
The County and/or the other member jurisdictions of the JPA would also likely be required to
provide a credit guarantee for all or a portion of the “working capital” line of credit (estimated at
$20 million) which would be used to secure power purchase contracts and other necessary
expenses prior to the JPA becoming financially self-sufficient.
79
A budget for the various start-up activities associated with the implementation of a new Contra
Costa JPA for the purpose of CCE are outlined in more detail in Attachment B to this report,
which was prepared by the County’s CCE consultant, LEAN Energy, based on LEAN’s direct
experience with start-up costs for recently created CCE JPAs in neighboring Bay Area counties.
MCE, EBCE and PG&E Options
The options of joining MCE or EBCE, or remaining with existing PG&E service, are all likely to
involve little or no additional direct costs to the County or cities within the County that decide to
implement one of these options. However, under these options it is unlikely the County and
Contra Costa cities will be reimbursed for any of the consulting expenses and County staff costs
already incurred to evaluate CCE options, which so far total approximately $400,000.
MCE has recently provided clarification of its membership process, known as its Open Inclusion
Period, to the County and cities within the County that are not currently MCE members (see
Attachment C). This process involves no direct cost to the County, but does require the County or
other interested jurisdictions within the County to adopt a resolution, an ordinance, and execute a
memorandum of understanding with MCE, among other actions.
The costs associated with joining EBCE are not currently defined, but are expected to be low or
none. EBCE is still in the process of forming its JPA, with the first meeting of the JPA Board of
Directors expected in late January. Alameda County has funded the start-up costs for EBCE, and
cities in Alameda County have not been required to pay any costs to join EBCE. Based on this
experience to date, Alameda County staff anticipate that Contra Costa jurisdictions seeking to
join EBCE are likely to be granted membership at no cost or at a very low cost. However, the
terms of membership for jurisdictions outside of Alameda County seeking to join EBCE will
ultimately need to be decided by the EBCE Board of Directors, once it is seated.
If the Board of Supervisors is interested in giving consideration to joining EBCE, staff
recommends that the Board requests clarification on the terms of membership in EBCE from the
EBCE Board of Directors. Staff recommends that the Internal Operations Committee (IOC)
recommend to the Board of Supervisors that the Board direct DCD to request terms of
membership in EBCE from the EBCE Board of Directors on behalf of the County.
Regarding continuation of current PG&E service, the financial implications are very transparent.
No expense or action of any kind from the County or other Contra Costa jurisdictions is required.
Attachments
Attachment A_Draft Community Choice Energy Technical Study
Attachment B_Draft CCE Implementation Budget
Attachment C_MCE Membership Requirements_11-8-16
80
DRAFT
Technical Study for Community Choice Aggregation
Program in Contra Costa County
Prepared by:
With
MRW & Associates, LLC
1814 Franklin Street, Ste 720
Oakland, CA 94612
Economic
Development
Research Group
Boston, MA
Sage Renewables
San Francisco, CA
November 30, 2016
Attachment A
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Table of Contents
Executive Summary ................................................................................................................ i
Loads and Forecast ........................................................................................................................ ii
CCE Power Supplies ....................................................................................................................... iii
CCE Rate Analysis Results .............................................................................................................. iv
Macroeconomic and Job Impacts ................................................................................................... vi
Comparative Analysis of CCE Options .......................................................................................... viii
Conclusions ................................................................................................................................... x
Chapter 1: Introduction ......................................................................................................... 1
What is a CCE? ...............................................................................................................................1
Assessing CCE Feasibility ................................................................................................................2
Chapter 2: Economic Study Methodology and Key Inputs ....................................................... 3
Contra Costa County Loads and CCE Load Forecasts ........................................................................5
CCE Supplies ..................................................................................................................................8
Power Supply Cost Assumptions ........................................................................................................ 11
Local Solar Analysis ............................................................................................................................ 13
Local Solar Modeled in the CCE Scenarios ......................................................................................... 19
Greenhouse Gas Costs ....................................................................................................................... 19
Other CCE Supply Costs ...................................................................................................................... 19
PG&E Rate and Exit Fee Forecasts ................................................................................................. 20
PG&E Bundled Generation Rates ....................................................................................................... 20
PG&E Exit Fee Forecast ...................................................................................................................... 21
Pro Forma Elements and CCE Costs of Service ............................................................................... 22
Pro Forma Elements ........................................................................................................................... 22
Startup Costs ...................................................................................................................................... 23
Administrative and General Cost Inputs ............................................................................................ 24
Cost of Service Analysis and Reserve Fund ........................................................................................ 24
Chapter 3: Cost and Benefit Analysis .................................................................................... 26
Scenario 1 (Minimum RPS Compliance)......................................................................................... 26
CCE Average Costs .............................................................................................................................. 26
Residential Bill Impacts ...................................................................................................................... 27
Greenhouse Gas Emissions ................................................................................................................ 28
Scenario 2 (Accelerated RPS) ........................................................................................................ 29
CCE Average Costs .............................................................................................................................. 29
Residential Bill Impacts ...................................................................................................................... 30
GHG Emissions ................................................................................................................................... 31
Scenario 3 (Minimum RPS Compliance plus Local Procurement) .................................................... 32
CCE Costs ............................................................................................................................................ 32
Residential Bill Impacts ...................................................................................................................... 33
GHG Emissions ................................................................................................................................... 33
Scenario 4 (Accelerated RPS plus Local Procurement).................................................................... 34
CCE Average Costs .............................................................................................................................. 34
Residential Bill Impacts ...................................................................................................................... 35
GHG Emissions ................................................................................................................................... 36
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Chapter 4: Sensitivity of Results to Key Inputs ...................................................................... 37
Lower Participation Sensitivity ..................................................................................................... 37
Higher Local Renewable Power Prices Sensitivity .......................................................................... 38
Higher Renewable Power Prices Sensitivity ................................................................................... 38
Higher Exit Fee (PCIA) Sensitivity .................................................................................................. 39
Lower PG&E Portfolio Cost Sensitivity .......................................................................................... 39
Higher Natural Gas Prices Sensitivity ............................................................................................ 40
Stress Case and Sensitivity Comparisons ....................................................................................... 40
Conclusions ................................................................................................................................. 43
Chapter 5: Macroeconomic Impacts ..................................................................................... 44
How a CCE interacts with the Surrounding Economy ..................................................................... 44
Job Impacts of Proposed CCE Scenarios ........................................................................................ 45
Overview of Scenario Effects ............................................................................................................. 45
Resulting Impacts on Jobs .................................................................................................................. 48
Allocation of Earned Income Gains ............................................................................................... 54
Chapter 6: Other Risks ......................................................................................................... 57
Financial Risks to CCE Members .................................................................................................... 57
Procurement-Related Risks .......................................................................................................... 58
Legislative and Regulatory Risks ................................................................................................... 59
PCIA Uncertainty .......................................................................................................................... 59
Impact of High CCE Penetration on the PCIA ................................................................................. 59
Impact of High CCE Penetration on Low-Carbon Resources ............................................................ 60
Bonding Risk ................................................................................................................................ 60
Chapter 7: Comparative Analysis of CCE Options .................................................................. 62
Rates ........................................................................................................................................... 63
GHG Reduction ............................................................................................................................ 64
Local Economic Benefits ............................................................................................................... 65
CCE Governance: Voting ............................................................................................................... 65
CCE Governance: Other ................................................................................................................ 68
Timing and Process to Join/Form .................................................................................................. 69
Costs to Join the CCE .................................................................................................................... 71
Exiting the CCE ............................................................................................................................. 71
Remaining With PG&E .................................................................................................................. 72
Summary ..................................................................................................................................... 72
Chapter 8: Other Issues Investigated .................................................................................... 75
Synergies on the Northern Waterfront ......................................................................................... 75
“Minimum” CCE Size? .................................................................................................................. 76
Individuals and Communities Self-Selecting 100% Renewables ...................................................... 77
Competition with a PG&E Solar Choice Program ........................................................................... 78
Differences Between the Analyses for Contra Costa and Alameda Counties ................................... 79
Chapter 9: Conclusions ....................................................................................................... 82
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List of Acronyms
AAEE Additional Achievable Energy Efficiency
CAISO California Independent System Operator
CBA Collective Bargaining Agreement
CCA Community Choice Aggregation
CCE Community Choice Energy
CEC California Energy Commission
CPUC California Public Utilities Commission
EE Energy Efficiency
EBCE East Bay Community Energy
ESPs Energy Service Providers
FY Fiscal Year
GHG Greenhouse Gas
GRP Gross Regional Product
GWh Gigawatt-hour (= 1,000 MWhs)
IOU Investor-Owned Utility
I/T Information Technology
JEDI Jobs and Economic Impact (model)
JPA Joint Powers Authority
kWh Kilowatt-hour
MW Megawatt
MWh Megawatt-hour
NREL National Renewable Energy Laboratory
PCIA Power Charge Indifference Adjustment
PEIR Programmatic Environmental Impact Report
PG&E Pacific Gas & Electric
REC Renewable Energy Credit
REMI Regional Economic Modeling Inc
RPS Renewable Portfolio Standard
SB 350 Senate Bill 350
TURN The Utility Reform Network
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Executive Summary
Main Findings
1. This study finds that the jurisdictions in Contra Costs County studied in this report have
several options for implementing a Community Choice Energy (CCE) program that
would likely result in lower GHG emissions, increased local renewable energy
generation, and increased local job creation compared to remaining with current
electricity service from the Pacific Gas and Electric Company (PG&E).
2. The electricity rates charged under various CCE scenarios available to the jurisdictions
covered in this study would likely be similar or less than the rates charged by PG&E for
comparable service. The degree to which CCE rates are reduced below comparable
PG&E rates depends in large part on the extent to which the CCE pursues policy
objectives other that rate minimization in its energy procurement practices. Competing
policy objectives may include increasing the supply of locally generated renewable
energy, promote energy efficiency, and maximizing local employment generated from a
CCE program.
3. This study finds that Contra Costa County includes enough technically feasible locations
to meet a significant proportion of electricity demand for the area studied through locally
generated renewable energy. Forty percent of the technically feasible sites fall within the
Northern Waterfront Economic Development Initiative area.
4. The implementation of a CCE program within the studied area is projected to create
between 500 and 1000 new jobs within Contra Costa County compared to remaining with
current PG&E service, depending on the CCE option implemented.
5. This study compares three CCE program alternatives to current PG&E service and
identifies the tradeoffs associated with these four alternatives. The decision of which
program alternative to implement will require policy makers to balance costs and
potential risks and benefits of each option, which are described in detail.
Purpose of this Study
California Assembly Bill 117, passed in 2002, established Community Choice Aggregation in
California to provide the opportunity for local governments or special jurisdictions to procure or
provide electric power for their residents and businesses. On March 15, 2016, the Contra Costa
County (County) Board of Supervisors directed County staff to work with cities within the
County to obtain electrical load data from PG&E for conducting a technical study of options for
implementing CCE within the County’s unincorporated area and the 14 cities within the County
not currently participating in a CCE program. The Board of Supervisors further directed the
CCE technical study to compare alternatives for implementing CCE (i.e., establishing a Contra
Costa County-Only CCE or joining one of the neighboring CCEs – MCE Clean Energy or East
Bay Community Energy) to the option of remaining with PG&E.
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To assess whether a stand-alone CCE is “feasible” in Contra Costa County, the local objectives
must be laid out and understood. Based on the specifications of the initial request for proposals
and input from the County, this study:
Quantifies the electric loads that a Contra Costa County CCE would serve;
Includes analysis of in-county renewable generation;
Compares the rates that could be offered by the CCE to PG&E’s rates;
Calculates the macroeconomic development and employment benefits of CCE formation;
and
Compares the benefits and risks of forming a CCE or joining a neighboring CCE versus
remaining on PG&E bundled service.
Loads and Forecast
Figure ES-1 provides a snapshot of Contra Costa County bundled electric load in 2015 by city
and by rate class.1 As the figure shows, total bundled electricity load in 2014 from Contra Costa
County was approximately 4,000 GWh. The unincorporated areas of the County represented
25% of County load, and the cities of Concord and Pittsburg were together responsible for
another 25%. Residential and commercial customers made up most the County load, with
smaller contributions from the industrial and public sectors.
Figure ES-1. PG&E’s 2015 Bundled Load in Contra Costa County
by Jurisdiction and Rate Class
1 “Bundled” load includes only load for which PG&E supplies the power; it excludes load from Direct Acces s
customers, load in the jurisdiction of another CCA provider, and load met by customer self -generation. This
excludes load originating in the cities of El Cerrito, Lafayette, Richmond, San Pablo, and Walnut Creek, which are
served by Marin Clean Energy.
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CCE Power Supplies
The CCE’s primary function is to procure supplies to meet the electrical loads of its customers.
By law, the CCE must also supply a certain portion of its sales to customers from eligible
renewable resources. This Renewable Portfolio Standard (RPS) requires 33% renewable energy
supply by 2020, increasing to 50% by 2030. The CCE may additionally choose to source a
greater share of its supply from renewable sources than the minimum requirements, or may seek
to otherwise reduce the environmental impact of its supply portfolio. The CCE may also use its
procurement function to meet other objectives, such as sourcing a portion of its supply from local
projects to promote economic development in the County. The four supply scenarios considered
in this analysis are summarized in Table ES-1.
Table ES-1: Four Scenarios Modeled2
Scenario: 1 2 3 4
% RPS-Eligible in 2020 33% 50% 33% 50%
% RPS-Eligible in 2030 50% 80% 50% 80%
Share of RPS-Eligible from Local Resources 0% 0% 50% 50%
Local Renewable Development
The CCE may choose to contract with or develop renewable projects within Contra Costa
County to promote economic development or reap other benefits. This study found 1,395 parcels
that met the established criteria and 1,875 individual sites within the identified parcels where
either a solar shade structure, large rooftop or ground mounted system could be developed.
Table ES-2 shows the total solar PV generation capacity within the County based on the
methodology and assumptions Chapter 3.
Table ES-2. Total PV Solar Generation Potential and Build Cost
Ground Mount Shade Structure Roof Mounted Total
PV Capacity (MW) 1,891 1,320 144 3,355
PV Production (GWh) 3,025 2,113 230 5,369
Build Cost ($ Millions) $3,417 $3,977 $371 $7,660
Build Cost ($/Watt) $1.99 $3.10 $2.62 $2.56
No of PV Systems 845 886 144 1,875
2 Customer-sited solar is not considered RPS-eligible in California and is not included in the RPS procurement in
these scenarios. Customer-sited solar is incorporated in this analysis as a reduction to the CCE’s load.
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CCE Rate Analysis Results
Scenarios 1 and 3 (Simple Renewable Compliance)
In Scenario 1, the CCE meets the mandated 33% RPS requirement in 2020 and the 50% RPS
requirement in 2030, plus the 55% proposed target between 2030 and 2038. Annual GHG
emissions are 50% lower on average than PG&E’s forecasted annual GHG emissions by
assuming a fraction of the non-RPS power is provided by large hydroelectric resources.
Figure ES-2 summarizes the results of Scenario 1. The figure shows the total average cost of the
Contra Costa County CCE to serve its customers (vertical bars) and the comparable PG&E
generation rate (line).3 Of the CCE cost elements, the greatest cost is for non-renewable
generation (including large hydroelectric), followed by the cost for renewable generation, which
increases over the years per the RPS requirements. Another important CCE customer cost is the
Power Charge Indifference Adjustment (PCIA), which is the CPUC-mandated charge that PG&E
must impose on all CCE customers.4
Under Scenario 1, the differential between PG&E generation rates and the average cost for the
Contra Costa County CCE to serve its customers (aka the CCE rates) is positive in each year
(i.e., CCE rates are lower than PG&E rates). As a result, Contra Costa County CCE customers’
average generation rate (including contributions to the reserve fund) can be set at a level that is
lower than PG&E’s average customer generation rate in each year.
Scenario 3 is the same as Scenario 1 except that by 2028 one-half of the renewable power is
provided by local resources. The differential between PG&E generation rates and Contra Costa
County CCE customer rates in Scenario 3 is lower than in Scenario 1; however, the expected
Contra Costa County CCE rates continue to be lower than the forecast PG&E generation rates
for all years from 2018 to 2038.
3 All rates are in nominal dollars. Note that these are NOT the full rates shown on PG&E bills. They are only the
generation portion of the rates. Other parts of the rate, such as transmission and distribution, are not included, as
customers pay the same charges for these components regardless of who is providing their power.
4 Per current regulations, the PCIA fee is expected to decrease in most years beginning in 2019 and to have less of
an impact on CCE customer rates over time as resources expire from PCIA-eligibility for CCE customers. However,
given that PCIA regulations are subject to change, the possibility that PCIA rates may not fall as expected is
considered in the High PCIA scenario.
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Figure ES-2. Scenario 1 Forecast Average CCE Cost and PG&E Rates, 2018-2038
Scenarios 2 and 4 (Accelerated RPS)
Under Scenario 2, the Contra Costa County CCE starts with 50% of its load being served by
renewable sources in 2017, and increases this at a quick pace to 80% renewable energy content
by 2030. Scenario 4 is the same as Scenario 2 except that by 2027 one-half of the renewable
power is provided by local resources.
The differential between PG&E generation rates and Contra Costa County CCE customer rates
in Scenario 2 and 4 is lower than in Scenarios 1 and 3; however, the expected Contra Costa
County CCE rates continue to be lower than the forecast PG&E generation rates for all years
from 2018 to 2038.
Greenhouse Gas Emissions
Under Scenarios 1 and 3, we include enough GHG-free hydroelectric power so that the Contra
Costa County CCE’s GHG emissions rate is about half of PG&E’s GHG emissions rate. This
requires using large hydroelectric power for 35% of the CCE’s generation portfolio, on average
from 2018 to2038. Though this large hydroelectric power would not qualify for RPS
requirements, it is considered a non-GHG emitting resource. 5 Under Scenario 2 and 4 these
additions of large hydro power are not needed once the high renewable targets are met. The
result is a portfolio that averages 20% large hydro from 2018 to 2028.
5 While there is a limited supply of uncontracted large hydroelectric power, Marin Clean Energy a nd Sonoma Clean
Power have been successful in procuring this resource. To account for the limited supply, we added a 10% premium
to the cost of this power.
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Figure ES-4 compares the Scenario 2 GHG emissions from 2018-2038 for the Contra Costa
County CCE with what PG&E’s emissions would be for the same load if no CCE were formed.
Since Scenario 2 has a higher renewable generation target (80% by 2030), the hydroelectric
generation necessary to achieve the same GHG emissions reduction is lower. Because of trading
off large hydro for RPS-eligible energy, GHG emissions in Scenario 2 are the same as Scenario 1
through 2030, after which the CCE's portfolio will produce half the GHG emissions compared to
PG&E.
Note that the analysis assumes “normal” hydroelectric output for PG&E. During the drought
years, PG&E’s hydro output has been at about 50% of normal, and the utility has made up these
lost megawatt-hours through additional gas generation. This means that the “normal” PG&E
emissions shown here are lower than the “current” emissions. If, as is expected by many experts,
the recent drought conditions are closer to the “new normal”, then PG&E’s GHG emissions in
the first 8 years would be approximately 30% higher. Depending on whether the CCE were
similarly affected by limited hydroelectric supply, the CCE’s emissions may increase as well.
Table ES-4. Comparative GHG total emissions for PG&E and Contra Costa CCA
GHG emissions PG&E (KTonnes)6 Contra Costa CCA
(KTonnes) Savings (%)
Scenario 1 5,882 2,957 50%
Scenario 2 5,882 2,693 54%
Scenario 3 5,882 2,957 50%
Scenario 4 5,882 2,693 54%
Macroeconomic and Job Impacts
The local economic development and jobs impacts for the four scenarios were analyzed using the
dynamic input-output macroeconomic model developed by Regional Economic Models, Inc.
(REMI). The model accounts for not only the impact of direct CCE activities (e.g., local project
installations for two of the four scenarios, program administration), but also how the rate savings
that County households and businesses might experience with a CCE ripple through the local
economy, creating more jobs and regional economic growth.
A CCE can also offer positive economic development and employment benefits to the County.
The CCE could create approximately 500 to 1000 additional annual jobs in the County plus an
additional 80 to 700 jobs in the neighboring counties depending on the scenario. The job
6 Thousands of metric tons
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impacts include not just the stimulus from program-related effects but jobs resulting from
multiplier effects and competitiveness effects. Scenario 4 – with the smallest of net rate savings
for the County’s electric customers poses the largest investment for small-solar across the local
economy. Figure ES-3 illustrate this through high-level results expressed as annual job changes
for the Scenario 4.
Figure ES-3. Scenario 4 Regional Annual Jobs Impacts, 2018 to 2038
The economic activity generated by the CCE results in incremental employment in a variety of
sectors. Figure ES-4 shows the job impacts (direct and indirect) by sector for Scenario 4 in 2021
(the year in which the CCE’s assumed solar investment is maximum).
0
200
400
600
800
1000
1200
201820192020202120222023202420252026202720282029203020312032203320342035203620372038JobsContra Costa Surr. Region
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Figure ES-4. Contra Costa Job Impacts by Sector Scenario 4, 2021 and 2038
Comparative Analysis of CCE Options
Having the County and its cities form its own Joint Powers Authority (JPA) and CCE Program is
not the only possibility for CCE participation. First, the Counties and/or its cities may join MCE
Clean Energy (MCE). In fact, five cities in the County—El Cerrito, Lafayette, Richmond, San
Pablo, and Walnut Creek—are already members of MCE. These cities joined between 2012 and
2016, and have full standing on MCE’s board of directors. Second, the County and/or its cities
could join East Bay Community Energy (Alameda County, EBCE). While this CCE has not
formally been formed—the Alameda County Board of Supervisors and the respective city
Councils are currently taking up the matter, and the JPA board may be seated as early as January
2017, with delivery of power beginning in late 2017. Furthermore, the County and each city
need not join one or other CCE en masse, but instead can join one or the other CCEs individually
(or neither).
Table ES-6 below provides a qualitative summary of the differences and similarities among these
options. While a quantitative comparison would appear to provide more rigor, in this case it
would provide only false precision. First and foremost, two of the potential CCE options are
with entities which, while potentially viable, do not yet exist. Without power contracts, portfolios
or procurement guidelines and policies, it would be unwise to claim that EBCE or a potential
Contra Costa-only CCE would have rates or greenhouse gas emissions higher or lower than the
other. Comparisons against MCE can be somewhat more reasonably asserted; however, its
stated goals—greater renewable energy content, lower greenhouse gas emissions, local
generation, and comparable rates—are nearly identical to those stated by EBCE, so as to make
long-range rate and emissions distinctions immaterial. Thus, the qualitative comparisons
0 50 100 150 200 250
Forestry, Fishing, & Rel. Activities
Mining
Utilities
Construction
Manufacturing
Wholesale Trade
Retail Trade
Transportation & Warehsg
Information
Finance & Insur.
Real Estate & Rental-Leasing
Professl, Scientific, & Tech Srvcs
Management of Companies &…
Admin. & Waste Mngmnt Srvcs
Educ. Srvcs
Health Care & Social Assist
Arts, & Recreation
Hotels & Food Services
Other Services
Local Govt
2021
Direct non-direct
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provided in the table do not provide sharp distinctions between the CCE options.7 All these
options are expected to provide similar rates and GHG emissions, with differences arising from
variations in the priorities and procurement decisions of the individual governance boards. What
truly distinguishes these options are primarily governance options (i.e., in-county only versus
shared with other entities) and the amount of risk assumed (i.e., developing or signing on with a
new CCE versus joining one with a record of satisfactory performance).
Table ES-5. Comparison of Contra Costa CCE Options
Criterion Form CCCo
JPA Join MCE Join EBCE Stay with
PG&E
Rates Likely lower Likely Lower Likely Lower Base
GHG Reduction Potential Over
Forecast Period Some Some Some Base
Local Control/Governance Greatest Some Greater None
Local Economic Benefits Greatest Some Greater Minimal
Start Up Costs/Cost to Join Low, but
greater risk8 None
Unknown, but
likely to be
none
None
Level of Effort Greatest Minimal Greater None
Program Risks Greatest Minimal Some Base
Timing (earliest) Mid-Late-
2018 Late-2017 Mid-2018 N/A
7 Differences between the CCE options and the option to stay with PG&E are more marked and better quantifiable,
given that information on PG&E’s power portfolios, procurement plans, and costs are at least partially available
through various filings and applications PG&E has made before the CPUC. The comparisons provided above
between the CCE’s rates and PG&E’s rates takes advantage of this information and market data on power
procurement costs to develop quantitative comparisons between the CCE and PG&E opti ons.
8 Start-up costs incurred by the County or others are likely to be reimbursed by the JPA.
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Conclusions
Overall, a CCE in Contra Costa County appears feasible. Given current and expected market and
regulatory conditions, a Contra Costa County CCE should be able to offer its residents and
businesses electric rates that are less than those available from PG&E.
Sensitivity analyses suggest that these results are relatively robust. Only when very high
amounts of renewable energy are assumed in the CCE portfolio, combined with other negative
factors, such as higher PCIA rates, higher prices for local renewable power, and lower PG&E
costs, do PG&E’s rates become consistently more favorable than the CCE’s.
A Contra Costa County CCE would also be well positioned to help facilitate greater amounts of
renewable generation to be installed in the County. Because the CCE would have a much greater
interest in developing local solar than PG&E, it is much more likely that such development
would occur with a CCE in the County than without it.
The CCE can also reduce the amount greenhouse gases emitted by the County if the CCE
prioritizes this goal. Because PG&E’s supply portfolio has significant carbon-free generation
(from large hydroelectric and nuclear generators), the CCE would need to contract for significant
amounts of hydroelectric or other carbon-free power above and beyond the required qualifying
renewables to reduce the County’s GHG footprint from electricity use. This analysis assumes
that the CCE procures enough GHG-free generation to halve PG&E’s GHG emissions rate,
subject to constraints on the minimum share of market supplies in the CCE portfolio.
A CCE can also offer positive economic development and employment benefits to the County.
At the peak, the CCE could create approximately 500 to 1000 new jobs in the County plus
additional jobs in neighboring counties. What may be surprising is that much of the economic
benefits come from reduced rates: residents and, more importantly, businesses can spend and
reinvest their bill savings, and thus generate greater economic impacts.
While the analytical focus of this report has been on a stand-alone Contra Costa County CCE,
that is not the only choice for Contra Costa communities. Overall, there is insufficient data to
suggest that a stand-alone Contra Costa CCE would offer lower rates or greater GHG savings
than joining MCE or EBCE. Either forming or joining a CCE would likely offer modestly lower
rates, more local economic development, and similar or lower GHG emissions than remaining
with PG&E. Joining MCE would likely result in the quickest path to CCE implementation,
however at a loss of local control and CCE policy formation. Because it has yet to be formed,
joining with EBCE would take longer than joining the already-established MCE, but would offer
greater input into the CCE’s policies and formation.
Although all the CCE program options available to the jurisdictions studied would likely provide
both environmental and economic benefits compared to PG&E, continuing service from PG&E
remains an option for not only a community but also for any individual or business whose
community has selected CCE service. PG&E is an experienced power provider and is regulated
by the state. Furthermore, remaining with PG&E takes no city action. Lastly, simply because a
Contra Costa community does not join a CCE in 2017 or 2018 does not necessarily preclude it
from doing so in the future, although waiting may result in an “entry fee” or perhaps a high
PCIA rate.
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Chapter 1: Introduction
On March 15, 2016, the Contra Costa County (County) Board of Supervisors directed County
staff to work with cities within the County to obtain electrical load data from the Pacific Gas and
Electric Company (PG&E) for the purpose of conducting a technical study of options for
implementing Community Choice Energy (CCE) within the County’s unincorporated area and
the 14 cities within the County not currently participating in a CCE program. The Board of
Supervisors further directed the CCE technical study to compare the following alternatives for
implementing CCE to the option of remaining with current electrical service from PG&E:
1. Form a new Joint Powers Authority (JPA) of the County and interested cities within
Contra Costa County for the purpose of CCE;
2. Form a new JPA in partnership with Alameda County and interested cities in both
counties; and
3. Join the existing CCE program initiated in Marin County, known as Marin Clean Energy
(MCE).
The County and the 14 Contra Costa cities not currently participating in a CCE program all
authorized the collection of load data from PG&E for this technical study. In addition, the
County and the cities of Brentwood, Clayton, Concord, Martinez, Pleasant Hill, Pittsburg and
San Ramon, and the Towns of Danville and Moraga, contributed funding for the completion of
this study.
What is a CCE?
California Assembly Bill 117, passed in 2002, established Community Choice Aggregation (also
known as Community Choice Energy or “CCE”) in California, for the purpose of providing the
opportunity for local governments or special jurisdictions to procure or provide electric power
for their residents and businesses.
Under existing rules administered by the California Public Utilities Commission, PG&E must
use its transmission and distribution system to deliver the electricity supplied by a CCE in a non-
discriminatory manner. That is, it must provide these delivery services at the same price and at
the same level of reliability to customers taking their power from a CCE as it does for its own
full-service customers. By state law, PG&E also must provide all metering and billing services
such that customers receive a single electric bill each month from PG&E, which would
differentiate the charges for generation services provided by the CCE from the charges for
PG&E delivery services. Money collected by PG&E on behalf of the CCE must be remitted in a
timely fashion (e.g., within 3 business days).
As a power provider, the CCE must abide by the rules and regulations placed on it by the State
and its regulating agencies, such as maintaining demonstrably reliable supplies, fully cooperating
with the State’s power grid operator, and meeting renewable procurement requirements.
However, the State has no rate-setting authority over the CCE; the CCE may set rates as it sees
fit so as to best serve its constituent customers.
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Per California law, when a CCE is formed all the electric customers within its boundaries will be
placed, by default, onto CCE service. However, customers retain the right to return to PG&E
service at will, subject to whatever administrative fees the CCE may choose to impose.
California currently has five active CCE Programs: MCE, serving Marin County and selected
neighboring jurisdictions; Sonoma Clean Power, serving Sonoma County; CleanPowerSF,
serving San Francisco City and County; Peninsula Clean Energy, serving San Mateo County; and
Lancaster Choice Energy, serving the City of Lancaster (Los Angeles County). Numerous other
local governments are also investigating CCE formation, including Alameda County; Los
Angeles County; Monterey Bay region; Santa Barbara, San Luis Obispo and Ventura Counties;
and Humbolt County to name but a few.
Assessing CCE Feasibility
In order to assess whether a CCE is “feasible” in Contra Costa County, the local objectives must
be laid out and understood. Based on the specifications of the initial request for proposals and
input from the County, this study:
Quantifies the electric loads that a Contra Costa County CCE would serve;
Estimates the costs to start-up and operate the CCE;
Considers four scenarios with differing assumptions concerning the amount of
GHG-free power and local renewable power being supplied to the CCE so as to
assess the costs, greenhouse gas emissions reductions, and local economic
development opportunities possible with the CCE;
Includes analysis of in-county renewable generation;
Compares the rates that could be offered by the CCE to PG&E’s rates;
Quantitatively explores the rate competitiveness of the four scenarios to key input
variables, such as the cost of natural gas;
Calculates the macroeconomic development and employment benefits of CCE
formation; and
Compares the benefits and risks of forming a CCE or joining a neighboring CCE
versus remaining on PG&E bundled service.
For comparison, the differences in the results between this study and that conducted for Alameda
County will be described and underlying reasons explained.
This study was conducted by MRW & Associates, LLC (MRW). MRW was assisted by Sage
Renewables, which conducted the local renewable energy potential study, and by Economic
Development Research Group, which conducted the macroeconomic and jobs analysis contained
in the study.
This study is based on the best information available at the time of its preparation, using publicly
available sources for all assumptions to provide an objective assessment regarding the prospects
of CCE operation in the County. 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.
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Chapter 2: Economic Study Methodology and Key Inputs
This Chapter summarizes the key inputs and methodologies used to evaluate the cost-
effectiveness and cost-competitiveness of a Contra Costa CCE relative to PG&E under different
scenarios.9 It considers the regulatory requirements that a Contra Costa County CCE would need
to meet (e.g., compliance with renewable portfolio standard (RPS) requirements), the resources
that the County has available or could obtain to meet these requirements, and the PG&E rates
against which the CCE would be compete. It also describes the pro forma analysis methodology
that is used to evaluate the financial feasibility of the CCE.
The load and rate forecasts go out twenty years—through 2038. While all forecasting contains
an element of uncertainty, the years beyond 2030 are particularly uncertain and should be seen as
broadly indicative and not predictive.
Understanding the interrelationships of all the tasks and using consistent and coherent
assumptions throughout are critical to developing a meaningful analysis. Figure 1 shows the
analysis elements (blue boxes) and major assumptions (red ovals) and how they relate to each
other. As the figure illustrates, there are numerous interrelationships between the tasks. For
example, the load forecast is a function of not only the load analysis, but also of projections of
economic activity in the County.
Two important points are highlighted in this figure. First, it is critical that wholesale power
market assumptions are consistent between the CCE and PG&E. While there are reasons that
one might have lower or higher costs than the other for a particular product (e.g., CCEs can use
tax-free debt to finance generation projects while PG&E cannot), both will participate in the
wider Western US gas and power markets and therefore will be subject to the same underlying
market forces. Applying different power cost assumptions to the CCE than to PG&E, such as
simply escalating PG&E rates while deriving the CCE rates using a bottom-up approach, would
produce erroneous results. Second, virtually all elements of the analysis feed into the economic
and jobs assessment. As is described in detail in Chapter 5, this Study uses a state-of-the art
macroeconomic model that can account for numerous activities in the economy, which allows for
a much more comprehensive—and accurate—assessment than a simple input-output model.
9 The relative costs and merits of joining CCEs in neighboring counties are addressed in Chapter 7.)
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Figure 1. Task Map
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Contra Costa County Loads and CCE Load Forecasts
MRW used PG&E bills from 2015 for all PG&E bundled service customers within the Contra
Costa County region as the starting point for developing electrical load and peak demand
forecasts for the Contra Costa County CCE program.10 Figure 2 provides a snapshot of Contra
Costa County bundled load in 2015 by city and by rate class. PG&E’s total electricity load in
2015 from these customers was approximately 4,000 GWh.11 The unincorporated areas of the
county represented 25% of county load, and the cities of Concord and Pittsburg were together
responsible for another 25%. Residential and commercial customers made up most of the County
load, with smaller contributions from the industrial and public sectors (Figure 3). This same
sector-level distribution of load is also apparent at the jurisdictional level for most cities, except
for the city of Pittsburg, which has a significant industrial-sector footprint.
Figure 2. PG&E’s 2015 Bundled Load in Contra Costa County by Jurisdiction and Rate
Class
10 Detailed monthly usage data provided by PG&E to Contra Costa County. “Bundled” load includes only load for
which PG&E supplies the power; it excludes load from Direct Access customers, load in the jurisdiction of another
CCA provider, and load met by customer self-generation. This excludes load originating in the cities of El Cerrito,
Lafayette, Richmond, San Pablo, and Walnut Creek, which are served by Marin Clean Energy.
11 As determined from bill data provided by PG&E.
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Figure 3. PG&E’s 2015 Bundled Load in Contra Costa County by Rate Class
To estimate CCE loads from PG&E’s 2015 bundled loads, MRW assumed a CCE participation
rate of 85% (i.e., 15% of customers opt to stay with PG&E) and a three-year phase in period
from 2018 to 2020, with 33% of potential CCE load included in the CCE in 2018, 67% in 2019,
and 100% in 2020. To forecast CCE loads through 2038, MRW used a 0.4% annual average
growth rate, consistent with the California Energy Commission’s most recent electricity demand
forecast for PG&E’s planning area.12 The CCE load forecast is summarized in Figure 4, which
shows annual projected CCE loads by class.
To estimate the CCE’s peak demand in 2015,13 MRW multiplied the load forecast for each
customer class by PG&E’s 2015 hourly ratio of peak demand to load for that customer class.14
MRW extended the peak demand forecast to 2038 using the same growth rates used for the load
forecast. The peak demand forecast is summarized in Figure 5.
12 California Energy Commission. Form 1.1c California Energy Demand Updated Forecast, 2015 - 2025, Mid
Demand Baseline Case, Mid AAEE Savings. January 20, 2015
http://www.energy.ca.gov/2014_energypolicy/documents/demand_forecast_cmf/LSE_and_BA/
13 Peak demand is the maximum amount of power the CCE would use at any time during the year. It is measu red in
megawatts (MW). The CCE must have enough power plants on (or contracted with) at all times to meet 115% of
the expected peak demand.
14 Data obtained from PG&E’s dynamic load profiles for Public, Industrial, Commercial and Residential customers
(https://www.pge.com/nots/rates/tariffs/energy_use_prices.shtml) and static load profiles for Pumping and
Streetlight customers (https://www.pge.com/nots/rates/2016_static.shtml#topic2).
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Figure 4: CCE Load Forecast by Class, 2018-203815
Figure 5. CCE Peak Demand Forecast, 2017-2038
15 Load forecasted assumes 85% participation and three -year phase-in.
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CCE Supplies
The CCE’s primary function is to procure supplies to meet the electrical loads of its customers.
This requires balancing energy supply and demand on an hourly basis. It also requires procuring
generating capacity (i.e. the ability to provide energy when needed) to ensure that customer loads
can be met reliably.16 In addition to meeting the energy and capacity needs of its customers, the
CCE must meet other procurement objectives. By law, the CCE must supply a certain portion of
its sales to customers from eligible renewable resources. This Renewable Portfolio Standard
(RPS) requires 33% renewable energy supply by 2020, increasing incrementally to 50% by 2030.
According to PG&E’s Diablo Canyon nuclear plant retirement application, PG&E may commit
to purchasing additional renewable supply, targeting up to 55% of the total generation between
2030 and 2038, which the CCE would presumably at least match. The CCE may additionally
choose to source a greater share of its supply from renewable sources than the minimum
requirements, or may seek to otherwise reduce the environmental impact of its supply portfolio.
The CCE may also use its procurement function to meet other objectives, such as sourcing a
portion of its supply from local projects to promote economic development in the County.
The Contra Costa County CCE would be taking over these procurement responsibilities from
PG&E for those customers who do not opt out of the CCE to remain bundled customers of
PG&E. To retain customers, the CCE’s offerings and rates must compete favorably with those
of PG&E.
The CCE’s specific procurement objectives, and its strategy for meeting those objectives, will be
determined by the CCE through an implementation plan, startup activities, and ongoing
management of the CCE. A primary purpose of this portion of the study is to assess the
feasibility of establishing a CCE to serve Contra Costa County based on a forecast of costs and
benefits. This forecast requires making certain assumptions about how the CCE will operate and
the objectives it will pursue. To address the uncertainty associated with these assumptions, we
have evaluated four different supply scenarios and have generally made conservative
assumptions about the ways in which the CCE would meet the objectives discussed above. In no
way does this study prescribe actions to be taken by the CCE should one be established.
The four supply scenarios that we considered in this analysis are summarized in Table 1 and
described as follows:
1. Minimum RPS Compliance: The CCE meets the mandated 33% RPS requirement in
2020 and the 50% RPS requirement in 2030, plus the 55% RPS target after 2030. Annual
GHG emissions from the CCE portfolio are halved relative to PG&E’s bundled portfolio
16 The California Public Utilities Commission (CPUC) requires that CCEs and other load serving entities
demonstrate that they have procured resource adequacy capacity to meet at least 115% of their expected peak load.
Since Contra Costa County falls within the Greater Bay Area Local Reliability Area, the Contra Costa County CCE
must also meet its share of local resource adequacy requirements.
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through the addition of large hydroelectric power purchases, subject to a constraint that
5% of the CCE supply come from non-renewable market sources.17
2. Accelerated RPS: The CCE’s supply portfolio is set at 50% RPS in the first year and
increases to 80% RPS by 2030. As in Scenario 1, the remaining supply is a mix of
hydroelectric power and market purchases aimed at halving PG&E’s annual emissions
subject to a 5% minimum supply from market purchases.
3. Minimum RPS Compliance plus Local: The CCE meets the mandated 33% RPS
requirement in 2020 and the 50% RPS requirement in 2030, plus the 55% RPS target
after 2030. In addition, 50% of the total RPS generation is provided by local resources by
2030. Large hydroelectric and market supplies, and thus GHG emissions, are the same as
in Scenario 1.
4. Accelerated RPS plus Local: The CCE’s supply portfolio is set at 50% RPS in the first
year and increases to 80% RPS by 2030. In addition, 50% of the total RPS generation is
provided by local resources by 2030. Large hydroelectric and market supplies, and thus
GHG emissions, are the same as in Scenario 2.
Table 1: RPS-Eligible Procurement and GHG Emissions in Each Scenario18
Scenario
1
Scenario
2
Scenario
3
Scenario
4
Percent RPS-Eligible in 2020 33% 50% 33% 50%
Percent RPS-Eligible in 2030 50% 80% 50% 80%
Share of RPS-Eligible from Local
Resources 0% 0% 50% 50%
GHG Emissions compared to PG&E 50%
Lower
54%
Lower
50%
Lower
54%
Lower
To evaluate these scenarios, we assumed a simple portfolio consisting of RPS-eligible resources
and additional GHG-free resources in an amount dictated by the particular scenario, with the
balance of supply provided by non-renewable wholesale market purchases. In each case, we
17 For all scenarios we assume a minimum 5% non-renewable market supply to reflect operating constraints that
require flexible, dispatchable generation on the system and in local areas. The CCE may be able to reduce emissions
further through the use of energy storage or other measures to reduce the need for non -renewable power supplies,
likely at additional cost.
18 Customer-sited solar is not considered RPS-eligible in California and is not included in the RPS procurement in
these scenarios. Customer-sited solar is incorporated in this analysis as a reduction to the CCE’s load.
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assumed that the RPS portfolio was predominately supplied with solar and wind resources,
which are currently the low-cost sources of renewable energy. We assumed that solar and wind
each contributes 45% of the renewable energy supply on an annual basis. To provide resource
diversity and partly address the need for supply at times when solar and wind production are low,
we assumed the remaining 10% of renewable supply would be provided by higher-cost baseload
resources, such as geothermal or biomass.
In the early years, the CCE would have to purchase its required renewable power from the
market and existing resources. However, the study assumes that the CCE would contract with
new renewable resources, such that by 2030 most of its renewable power would come from new
resources. Figures 6 and 7 show the assumed build-out of these new resources under the first
(Minimum RPS Compliance) and the fourth (Accelerated RPS plus Local) scenarios described
above.
Figure 6. Senario 1 CCE Build-Out
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Figure 7. Scenario 4 CCE Build-Out
Power Supply Cost Assumptions
As discussed above, the CCE would procure a portfolio of resources to meet its customers’
needs, which would consist of a mix of renewable and non-renewable (i.e., wholesale market)
resources. As shown in Figure 8, the products to be purchased by the CCE consist generally of
energy, capacity and renewable attributes (which for counting purposes take the form of
renewable energy credits, or RECs).19
19 RECs are typically bundled with energy deliveries from renewable energy projects, with each REC representing 1
MWh of renewable energy. A limited number of unbundled RECs may be used to meet RPS requirements. For the
purpose of this study we have not considered unbundled RECs and have rather estimated costs based on renewable
energy contracts where the RECs are bundled.
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Figure 8. Power Supply Cost Elements
The CCE will procure supplies from the same competitive market for resources as PG&E. Thus,
we assume that the costs for renewable and non-renewable energy and for resource adequacy
(RA) capacity for the CCE are the same as for new purchases made by PG&E (discussed further
in our forecast of PG&E rates). Wholesale market prices for electricity in California are largely
driven by the cost of operating natural gas power plants, since these plants typically have the
highest operating costs and are the marginal units. Market prices are a function of the efficiency
of the marginal generators, the price of natural gas and the cost of GHG allowances. MRW
developed forecasts of these elements to derive a power price forecast to determine costs for the
CCE and PG&E. Large hydroelectric power prices are based on the market price forecast with a
10% premium to reflect the value of GHG benefits, flexibility and increasing demand from load
serving entities seeking clean power like the CCE. Capacity prices are based on prices for RA
contracts reported by the CPUC and on the cost to build a new combustion turbine power plant.
MRW developed a forecast of non-local utility scale renewable generation prices starting from
an assessment of the current market price for renewable power. For the current market price,
MRW relied on wind and solar contract prices reported by California municipal utilities and
CCEs in 2015 and early 2016, finding an average price of $49/MWh for the solar contracts,
$55/MWh for wind power and $80/MWh for geothermal.20 We used these prices as the starting
point for our forecast of CCE renewable energy procurement costs. For geothermal, which is a
relatively mature technology, we assumed that new contract prices would simply escalate with
inflation.
20 MRW relied exclusively on prices from municipal utilities and CCEs because investor -owned utility contract
prices from this period are not yet public. We included all reported wind and solar power purchase agreements,
excluding local builds (which generally come at a price premium), as reported in California Energy Markets, an
independent news service from Energy Newsdata, from January 2015-January 2016 (see issues dated July 31,
August 14, October 16, October 30, 2015, and January 15, 2016).
Power Supply
Costs
Renewable
Power
Energy
Excess Supply
Capacity RECs
Non-
Renewable
Power
Energy
Natural Gas
Greenhouse
Gas
Allowances
Capacity
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Solar and wind prices are a function of technology costs, which have generally been declining
over time; financing costs, which have been very low in recent years; and tax incentives, which
significantly reduce project costs, but phase out over time. In the near-term we would not expect
prices to increase as technology costs and continued tax incentives provide downward pressure
and likely offset any increase in financing costs or other competitive pressure from an increasing
demand for renewable energy in California. For utility scale wind prices, we relied on an expert
elicitation survey21 developed by Lawrence Berkeley National Laboratory (LBNL). According to
this survey, wind prices will decrease 24% by 2030 and 35% by 2050.22 For solar, we held
prices constant in nominal dollars through 2020. Beyond 2020, with increasing competitive
pressure due to the drive to a 50% RPS and the anticipated phase-out of federal tax incentives
(offset in part by declining technology costs), we would expect prices to increase somewhat and
have assumed they escalate at the rate of inflation. In addition, we also considered a high solar
cost scenario based on work performed by LBNL on the value of tax incentives. In the high
scenario, we assume that costs increase with the phase-out of federal tax incentives, without
being offset by declining technology costs. Figure 9 shows the resulting solar price forecasts for
the two scenarios.
Figure 9. Large-Scale Non-Local Solar Price Forecast
Local Solar Analysis
Pivotal to the evaluation of the local economic impacts of a Contra Costa CCE is an
understanding how much renewable energy can be developed within the County. This
21 “Expert elicitation survey on future wind and energy costs,” Nature Energy, September 12, 2016.
22 Relative to the 2014 wind prices. MRW also added the annual inflation increase.
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assessment focused on identifying local solar photovoltaic (PV) siting potential. Wind and
biomass energy were also evaluated, but were determined to be less feasible for Contra Costa
County.
The solar PV assessment is based on a comprehensive desktop review of countywide parcel data,
geographic features and solar energy potential. Table 2 shows the total solar PV generation
capacity within the County based on the methodology and assumptions described below.
Table 2. Total PV Solar Generation Potential and Build Cost
Ground
Mount Shade Structure Roof Mounted Total
PV Capacity (MW23) 1,891 1,320 144 3,355
PV Production (GWh) 3,025 2,113 230 5,369
Build Cost ($ Millions) $3,417 $3,977 $371 $7,660
Build Cost ($/Watt) $1.99 $3.10 $2.62 $2.56
No of PV Systems 845 886 144 1,875
Generation capacity was determined for the three types of possible solar PV installations:
Ground Mount, Shade Structure/Carport, and Roof Mount. The findings show that the County
has a solar PV generation capacity of 3,355 MW and annual solar electricity production potential
of 5,369 GWh. Figure 10 shows the aggregate Solar PV supply curve for all County
jurisdictions.
23 Local solar PV capacity measured at the panel (i.e., pre-inverter).
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Figure 10. Aggregate Solar PV Supply Cost Curve, All County
Siting Analysis
To assess the potential locations in Contra Costa County where solar PV could be developed, this
study utilized a Geographic Information System (GIS)-based desktop review, incorporating
aerial imagery and land-based data. The collected data was analyzed and potential solar PV
development sites were identified from criteria established through industry knowledge and input
from County stakeholders.
The agreed upon criteria are as follows:
The minimum acceptable parcel size is three acres. Smaller parcels will not be able to
hold an economically viable project. If a potential solar PV system size is below 500 kW
it was excluded from the list of potentially feasible sites and overall solar energy
capacity.24 Again, this measure ensures only realistic and economically feasible sites are
identified.
Based on input from the County, only specific tax codes and zoning areas were evaluated.
For example, areas such as Open Space or Parks have sufficient land area for solar PV
24 Residential and other small rooftop solar are accounted for in the California Energy Commission sales forecast
used to develop the CCE’s demand forecast.
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projects, but zoning restrictions would not allow for the development of these projects,
and these areas were removed from the approved scope.
In addition, to size and tax/zoning code designations, areas with poor ground quality
(marshland), excessive tree density or excessive sloping would prohibit cost-effective
solar PV development and were removed from the analysis.
Lastly, sites with existing solar were removed from the pool of potential parcels/sites.
Within each identified parcel is the potential for three different types of solar PV development.
On impervious land, such as a parking lot, it was assumed that solar PV carports would be
installed. On grassland or bare land areas, this analysis assumed a ground-mounted solar PV
system would be installed. Lastly, roof-mounted solar PV was assumed for any buildings found
in the parcel data that matched the approved criteria. Countywide, 92% of potential installation
sites were found to be either carport or ground-mount sites, with only 8% of the sites amenable
to roof-mounted PV (Figure 11). The size of the estimated solar PV system was found by
analyzing the total land area against the needed land required for solar PV development.
Figure 11. Potential Solar PV Sites by Installation Type
This study found 1,395 parcels that met the established criteria and 1,875 individual sites within
the identified parcels where either a solar shade structure, rooftop or ground-mounted system
could be developed. Table 3 shows the individual sites organized by type of solar PV system for
each jurisdiction in Contra Costa County.25
25 For maps, please see
https://www.dropbox.com/s/cb3rig66shny68j/Contra%20Costa%20CCE%20Solar%20Sitin g%20DRAFT%20Repor
t%20SA%202016-11-15%20Reduced%20Size.pdf?dl=0.
Carport
47%
Ground-
mount
45%
Rooftop
8%
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This assessment also calculated the amount of solar energy production for each of the potential
sites identified. The amount of energy production was found by multiplying the estimated system
size by an average solar yield. The average solar energy yield was created by designing sample
projects that matched the estimated system size in the solar software platform Helioscope.
Because Contra Costa County has a variety of solar exposure, multiple sites across the County
were designed/tested to find an average yield. Based on our testing, the average yield for Contra
Costa County is 1,600 (kWh/kW). The resulting amount of potential PV production per
jurisdiction is also provided in Table 3.
Table 3. Potential PV Production and Build Cost by Location
Jurisdiction PV Potential
(MW)
PV Production
(GWh)
Build Cost
($ Millions)
Alamo 14 23 $30,779,000
Antioch 462 739 $1,010,374,000
Brentwood 287 460 $599,685,000
Clayton 38 62 $71,171,000
Concord 370 593 $900,603,000
Crockett 58 93 $125,187,000
Danville 80 129 $177,801,000
El Cerrito 29 48 $73,161,000
El Sobrante 19 31 $42,020,000
Hercules 90 144 $200,511,000
Lafayette 8 13 $23,641,000
Martinez 313 502 $654,701,000
Moraga 24 39 $55,957,000
Oakley 121 194 $285,786,000
Orinda 22 36 $43,554,000
Pinole 47 77 $126,870,000
Pittsburg 314 502 $705,202,000
Pleasant Hill 60 96 $164,364,000
Port Costa 8 13 $13,501,000
Richmond 502 804 $1,261,541,000
Rodeo 35 57 $85,874,000
San Pablo 191 307 $459,784,000
San Ramon 158 254 $384,634,000
Walnut Creek 95 152 $269,795,000
Grand Total 3,355 5,369 $7,766,496,000
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Ranking
After the feasible solar sites and the corresponding solar PV capacity were identified, each site
was ranked. The ranking was weighted based on how important it was to the actual feasibility of
developing the site for solar PV and based on input from County stakeholders. The ranking
consisted of the following measures:
Figure 12. Weighted Ranking Categories
An overall ranking score was then applied to each individual site to illustrate the best and worst
sites for solar PV development. Sites were then grouped in tiers one through five, with one being
the best. In addition to the ranking score, industry knowledge indicates the best sites to develop a
feasible solar PV project will be larger than 1 MW, located on government land and will be a
ground-mounted solar array, the most cost-effective installation type. Below is a table showing
the key characteristics of the ranking analysis.
Table 4. Ranking Values for All Sites
Ranking
Tier
Sum of PV
Production (GWh) Sum of Total Price
Average Price per
Watt
1 1,309 $1,591,810,000 $2.13
2 1,167 $1,578,770,000 $2.37
3 1,105 $1,622,236,000 $2.57
4 868 $1,251,547,000 $2.56
5 919 $1,722,142,000 $3.07
Carport
47%
Ground-
mount
45%
Rooftop
8%
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Local Solar Modeled in the CCE Scenarios
To estimate the contribution of local solar to Contra Costa CCA's supply costs, we used the
supply curve shown in Figure 10. To translate the $/kW costs in the figure to $/MWh generation
costs, we used the pro forma model contained in the CPUC's RPS Calculator and the cost and
performance assumptions provided by Sage for the County. For example, the lowest-cost
projects at $1350/kW were estimated to have a generation cost of $68/MWh.
The generation cost was assumed to scale with installed cost. Since it is unlikely that all of the
identified sites would be developed in order of their increasing cost (and some sites may never be
developed regardless of economics), we assumed that 50% of the capacity identified in the cost
curve would be developed for the purpose of conservatively estimating average costs at each
level of local solar penetration. We calculated the average price for the cumulative developed
capacity forecast for each year (again, counting only 50% of the capacity of each developed
project towards the cumulative total). For Scenarios 3 and 4, we assumed that 50% of the CCA's
RPS supply would be provided by local solar by 2027, adding 620 MW of local solar under
Scenario 3 and 990 MW under Scenario 4 by 2030. (Scenarios 1 and 2 do not include any local
solar.)
Greenhouse Gas Costs
MRW estimated that the price of GHG allowances would equal the auction floor price stipulated
by the California Air Resources Board’s cap-and-trade regulations, consistent with recent auction
outcomes.26
Table 5. GHG Allowances price27
Total GHG costs were calculated by multiplying the allowance price by the amount of carbon
emitted per megawatt-hour for each assumed resource. For “system” purchases, MRW assumed
that the GHG emissions corresponded to a natural gas generator operating at the market heat rate.
This worked out to be, on average over 2018-2038, approximately $1.5/MWh delivered.28
Other CCE Supply Costs
The CCE is expected to incur additional costs associated with its procurement function. For
example, if the CCE relies on a third-party energy marketing company to manage its portfolio it
will likely incur broker fees or other expenses equal to roughly 5% of the forecasted contract
costs. The CCE would also incur costs charged by the California Independent System Operator
(CAISO) for ancillary services (activities required to ensure reliability) and other expenses.
26 California Code of Regulations, Title 17, Article 5, Section 95911 . Auction results available at
http://www.arb.ca.gov/cc/capandtrade/auction/results_summary.pdf.
27 For 2017, the amount listed corresponds to the GHG allowance price for PG&E according to the most recent
ERRA 2017 update. Pacific Gas & Electric ERRA 2017, A.16-06-003, Testimony November 2, 2016, Table 12-1.
28 The amount GHG emissions will depend on the generation portfolio. $1.5/MWh corresponds to the GHG
emissions costs under Scenario 1.
2017 2018 2019 2025 2030 2035 2038
$/tonne 13.2 14.7 15.9 24.4 34.7 49.8 61.8
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MRW added 5.5% to the CCE’s power supply cost to cover these CAISO costs. Finally, we
added an expense associated with managing the CCE’s renewable supply portfolio. Based on an
analysis of the expected CCE load shape and the typical generation profile of California solar
and wind resources, we observed that there will be hours in which the expected deliveries from
renewable contracts will be greater than the CCE’s load in that hour. This results from the
amount of renewable capacity that must be contracted to meet annual RPS targets and the
variability in renewable generation that leads to higher deliveries in some hours and lower
deliveries in other hours. When high renewable energy deliveries coincide with low loads, the
CCE will need to sell the excess energy, likely at a loss, or curtail deliveries, and potentially have
to make up those renewable energy purchases during higher load hours to comply with the RPS.
The result is that the procurement costs will be somewhat higher than simply contracting with
sufficient capacity to meet the annual RPS.
PG&E Rate and Exit Fee Forecasts
MRW developed a forecast of PG&E’s bundled generation rates and CCE exit fees in order to
compare the projected rates that customers would pay as Contra Costa County CCE customers to
the projected rates and fees they would pay as bundled PG&E customers.
PG&E Bundled Generation Rates
To ensure a consistent and reliable financial analysis, MRW developed a 20-year forecast of
PG&E’s bundled generation rates using market prices for renewable energy purchases, market
power purchases, greenhouse gas allowances, and capacity that are consistent with those used in
the forecast of Contra Costa County CCE’s supply costs. MRW additionally forecast the cost of
PG&E’s existing resource portfolio, adding in market purchases only when necessary to meet
projected demand. MRW assumed that near-term changes to PG&E’s generation portfolio would
be driven primarily by increases to the Renewable Portfolio Standard requirement in the years
leading up to 2030 and by the retirement of the Diablo Canyon nuclear units at the end of their
current license periods in 2024 and 2025. More information about this forecast is provided in
Appendix B.
MRW forecasts that, on average, PG&E’s generation rates will increase faster than inflation
through 2038, with 2038 rates more than 20% higher than today’s rates when considered on a
constant dollar basis (i.e., assuming zero inflation). Underlying this result are three distinct rate
periods:
1. An initial period of faster rate growth from 2018 to 2022 (1% annually above inflation);
2. A period of rate decline from 2023 to 2025 (3.5% annually below inflation), primarily
due to the retirement of Diablo Canyon29; and
3. A period of steeper rate growth between 2026 and 2030 (3.5% annually above inflation),
primarily due to the replacement of Diablo Canyon with more expensive resources:
energy efficiency, renewable generation, and fuel-fired generation. In addition, the
retirement of Diablo Canyon increases the demand in capacity with a consequent increase
in capacity prices.
29 More information can be found in the Appendix C
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4. A final period of moderate rate growth through 2038 (1% annually above inflation),
primarily due to the replacement of high-cost renewable power contracts currently in
PG&E’s portfolio with new lower-priced contracts (reflecting the significant fall in
renewable power prices in recent years).
PG&E’s bundled generation rates in each year of MRW’s forecast are shown in Figure 13, on
both a nominal and constant-dollar basis.
Figure 13: PG&E Bundled Generation Rates, nominal and constant-dollar forecasts
PG&E Exit Fee Forecast
In addition to the bundled rate forecast, MRW developed a forecast of the Power Charge
Indifference Adjustment (“PCIA”), which is a PG&E exit fee that is charged to CCE customers.
The PCIA is intended to pay for the above-market costs of PG&E generation resources that were
acquired, or which PG&E committed to acquire, prior to the customer’s departure to CCE. The
total cost of these resources is compared to a market-based price benchmark to calculate the
“stranded costs” associated with these resources, and CCE customers are charged what is
determined to be their fair share of the stranded costs through the PCIA.
MRW forecasted the PCIA charge by modeling expected changes to PCIA-eligible resources and
to the market-based price benchmark through 2038, using assumptions consistent with those
used in the PG&E rate model. Based on our modelling, we expect the PCIA to decline in most
years until it drops off completely around 2034. MRW’s forecast of the residential PCIA charge
through 2038 is summarized in Table 6.
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Table 6. PG&E Residential PCIA Charges
2018 2019 2020 2025 2030 2035 2038
¢/kWh 2.4 1.9 2.3 1.3 0.5 0.0 0.0
Pro Forma Elements and CCE Costs of Service
MRW conducted a pro forma analysis to evaluate the expected financial performance of the CCE
and the CCE’s competitive position vis a vis PG&E. The analysis was conducted on a forward-
looking basis from the expected start of CCE operations in 2018 through the year 2038, with
several cases considered to address uncertainty in future circumstances.
Pro Forma Elements
Figuer 14 provides a schematic of the pro forma analysis, outlining the input elements of the
analysis and the output results. The analysis involves a comparison between the generation-
related costs that would be paid by Contra Costa County CCE customers and the generation-
related costs that would be paid by PG&E bundled service customers. Costs paid by CCE
customers include all CCE-related costs (i.e., supply portfolio costs and administrative and
general costs) and exit fee payments that CCE customers will be required to make to PG&E.
As discussed in previous sections, supply portfolio costs are informed and affected by CCE
loads, by the requirements the CCE will need to meet (or will choose to meet) such as with
respect to renewable procurement, and by CCE participation levels, which can vary depending
on whether or not all cities in the County choose to join the CCE. Administrative and general
costs are discussed further below.
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Figure 14. Pro forma Analysis
Startup Costs
Table 7 shows the estimated CCE startup costs. They are based on the experience of existing
CCEs as well as from other CCE technical and feasibility assessments. Working capital is set to
equal one hundred days of CCE revenue30, or approximately $22 million. This amount would
cover the timing lag between when invoices for power purchases (and other account payables)
must be remitted and when income is received from the customers. Initially, the working capital
is provided to the CCE on credit from a bank. Typical power purchase contracts require payment
for the prior month’s purchases by the 20th of the current month. Customers’ payments are
typically received 60 to 90 days from when the power is delivered.
These startup costs are assumed to be financed over 5 years at 5% interest.
30 The working capital has been calculated in base to Scenario 1.
Inputs: selection of cities, scenarios, and sensitivity cases
Load
Forecast
PG&E
Generation Rate
Forecast
Supply Costs
Forecast
Adm. Costs
Forecast
Assessment of CCE viability and CCE customer rates vs. PG&E customer rates
(also accounts for reserve fund contributions)
Exit fees
Forecast
Local
renewable
cost forecast
Generation Rates paid by Contra Costa County CCE Customers
(also accounts for debt interest)
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Table 7. Estimated Start-Up Costs
Item Cost
Technical Study $200,000
JPA Formation/Development $100,000
Implementation Plan Development $50,000
Power Supplier Solicitation & Contracting $75,000
Staffing $700,000
Consultants and Legal Counsel $400,000
Marketing & Communications $250,000
PG&E Service Fees $75,000
CCA Bond $100,000
Miscellaneous $300,000
Total $2,250,000
Working Capital $21,500,000
Total $23,750,000
Administrative and General Cost Inputs
Administrative and general costs cover the everyday operations of the CCE, including costs for
billing, data management, customer service, employee salaries, contractor payments, and fees
paid to PG&E. MRW conducted a survey of the financial reports of existing CCEs to develop
estimates of the costs that would be faced by a Contra Costa County CCE. Administrative and
general costs are phased in from 2018 to 2020, as the CCE operations expand to cover the entire
territory of the County; after that, costs are escalated by 2% each year to account for the effects
of inflation.
Administrative and general costs are unchanged under the three renewable level scenarios, but do
vary based on how many cities join the CCE and the number of participating customer accounts.
As previously mentioned, a 15% opt-out rate has been assumed for customer participation.
Cost of Service Analysis and Reserve Fund
To determine annual CCE costs and the rates that would need to be charged to CCE customers to
cover these costs, MRW summed the two categories of CCE costs (i.e., supply portfolio costs,
and administrative and general costs) and added in debt financing to cover start-up costs and
initial working capital. Financing was assumed to be for a five-year period at an interest rate of
5%. These costs were divided by projected CCE loads to develop the average rate the CCE
would need to charge customers to cover its costs (“minimum CCE rate”).
To establish the Contra Costa County CCE rate, MRW adjusted the minimum CCE rate, if
needed, based on the competitive position of the CCE. In particular, when the total CCE
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customer rate (i.e., the minimum CCE rate plus the PG&E exit fee) was below the projected
PG&E generation rate,31 MRW increased the minimum CCE rate up to the amount needed to
meet the reserve refund targets while still maintaining a discount. MRW used the surplus CCE
revenue from these rate increases (“Reserve Fund”) in order to maintain Contra Costa County
CCE competitiveness with PG&E rates in years in which total CCE customer rates would
otherwise be higher than PG&E generation rates.32
31 For this analysis, MRW used the average of the projected PG&E generation rates across all rate classes, weighted
by the projected Contra Costa County CCE load in each rate class.
32 MRW applied a Reserve Fund cap of 15% of the annual operating cost. After this cap was reached, no further rate
increases were applied for the purpose of Reserve Fund contributions.
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Chapter 3: Cost and Benefit Analysis
As described in the prior chapter, as part of the pro forma analysis, MRW calculated Contra
Costa County CCE rates that would, where feasible, cover CCE costs and maintain long-term
competitiveness with PG&E. This chapter uses those rates to compare the costs and benefits of
the Contra Costa County CCE across four scenarios: (1) Minimum RPS Compliance, (2)
Accelerated RPS, (3) Minimum RPS Compliance plus Local Procurement, and (4) Accelerated
RPS plus Local Procurement. Costs and benefits are evaluated by comparing total CCE customer
rates (including PG&E exit fees) to PG&E generation.
Scenario 1 (Minimum RPS Compliance)
Under Scenario 1, the Contra Costa County CCE meets all RPS requirements (including
California State Senate Bill 350 and Diablo Canyon retirement proposal requirements), and 35%
of the total load over the 20-year period is met through large hydroelectricity33.
CCE Average Costs
Figure 15 summarizes the results of this scenario. The vertical bars represent the total Contra
Costa County CCE customer rate and the green line represents a comparable PG&E generation
rate.34 Non-renewable generation (including large hydroelectric) is responsible for the bulk of the
CCE's costs. Renewable generation costs will continue to increase throughout the forecast period
due to the increasing RPS standards. Regarding customer costs, the PCIA exit fee is expected to
decrease after 2020. Finally, the GHG allowance purchases represent a small portion of the total
costs because 60% of the non-renewable generation is met by hydroelectricity. This non-carbon
emitting resource therefore limits the need to purchase GHG allowances.
Note that this figure and the analogous ones to follow do not account for contributions to a rate
reserve fund or other potential CCE activities such as efficiency or other community programs.
Under Scenario 1, the differential between PG&E generation rates and Contra Costa County
CCE customer rates is positive in each year (i.e., CCE rates are lower than PG&E rates). As a
result, Contra Costa County CCE customers’ average generation rates (including contributions to
the reserve fund) can be set at a level that is lower than PG&E’s average customer generation
rate in each year. The annual differential between the PG&E rate and the total CCE customer
rate is expected to vary significantly over the course of this period (Figure 15). During the initial
period from 2018-2022, the differential between the two rates increases (i.e., the CCE becomes
more cost-competitive) as PG&E’s rates rise, and the exit fees charged to Contra Costa County
CCE customers fall as PG&E-owned gas plants expire from PCIA eligibility. Beginning in 2024,
the rate differential narrows due to a decrease in PG&E generation rates stemming from the
closure of the Diablo Canyon nuclear plant. After 2026, the difference between the two rates is
expected to increase as PG&E’s generation rates continue to increase and exit fees decline with
the expiration of additional resources from PCIA eligibility.
33 60% of the non-RPS generation in average for 2018-2038.
34 All rates are in nominal dollars
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Figure 15. Scenario 1 Forecast Average CCE Cost and PG&E Rates, 2018-203835
Residential Bill Impacts
Table 8 shows the average annual savings for Residential customers under Scenario 1. The
average annual bill for the residential customer on the Contra Costa County CCE program will
be on average 8% lower than the same bill on PG&E rates. Note that these rate impacts assume
that a rate stabilization reserve is funded during the first few years of the CCE’s existence.
Table 8. Scenario 1 Savings for Residential CCE Customers
Residential
Monthly
Consumption
(kWh)
Bill with
PG&E ($)
Bill with
Contra Costa
County CCA
($)
Savings ($) Savings (%)
2018 500 121 121 0 0%
2020 500 129 124 5 4%
2030 500 189 171 18 10%
2038 500 254 227 27 11%
35 This chart doesn’t include the reserve fund.
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Greenhouse Gas Emissions
Under Scenario 1, we model the Contra Costa County CCE to be 50% below PG&E’s GHG
emission rate. It can meet this goal by using large hydroelectric power to meet 35% of its
resource needs (60% of the non-RPS load). Though this large hydro power would not qualify for
RPS requirements, it is nevertheless a non-carbon emitting resource.
Figure 16 shows Contra Costa CCE’s generation portfolio mix (vertical bars) and GHG
emissions rate (brown line) under Scenario 1, along with PG&E’s GHG emissions rate for
comparison (blue line). Additional GHG savings can occur if additional renewables are added to
the portfolio (see Scenarios 2 and 4) or if a greater fraction of GHG-free resources (like large
hydro) is used.
PG&E GHG emissions are relatively low due to the diversity in PG&E’s electric mix. In addition
to renewable generation, over 40% of PG&E’s supply portfolio is made up of nuclear and large
hydroelectric generation, both of which are considered GHG-free generation technologies.
PG&E’s GHG emissions rate is expected to fall between 2018 and 2020 due to increases in RPS
procurement. In 2025, the retirement of the Diablo Canyon nuclear generation plant is expected
to more than double PG&E’s GHG emission rate as the utility increases its gas-fired generation
to make up for a share of the loss.36 In the following years PG&E’s GHG emissions are expected
to decrease as PG&E ramps up renewable procurement to meet its mandated RPS goals and the
additional RPS procurement required under the Diablo Canyon retirement proposal.37 In this
scenario, the CCA’s emissions rate is set to be approximately 50% of PG&E’s in each year,
subject to a 5% minimum supply from market purchases.
36 Even if PG&E replaces the nuclear generation with renewable power and other GHG -free resources, as proposed,
the new renewable resources will need to be balanced by flexible resources, which are likely to be at least in part
provided by fossil-fueled power and which will therefore increase PG&E’s GHG emissions.
37 Starting in 2030, the required RPS increases from 50% to 55% under PG&E’s proposal.
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Figure 16. Scenario 1 Contra Costa County CCE Supply Portfolio (vertical bars) and GHG
Emissions (lines) (“Normal” PG&E Hydro Conditions)
Scenario 2 (Accelerated RPS)
Scenario 2, from a renewable procurement perspective, is a more aggressive scenario. Under this
scenario, the Contra Costa County CCE starts with 50% of its load served by renewable sources
in 2018, and rapidly increases to 80% of its load served by renewable sources in 2030. In
addition, between 2018 and 2038 Contra Costa County will provide an average of 20% of its
supply though large hydroelectric sources38.
CCE Average Costs
Figure 17 summarizes the results for this scenario. The vertical bars represent the Contra Costa
County CCE customer rate, and the green line represents the PG&E generation rate. In this
scenario, the renewable power cost is the single largest element of the CCE rate, reflecting the
higher renewable content of this scenario. Non-renewable generation and the PCIA exit fee are
the second and third most expensive components, respectively. As in Scenario 1, the PCIA exit
fee is expected to decrease in most years beginning in 2020. Because of this scenario's larger
share of GHG-free generation between 2028 and 2038, the GHG allowance purchases are an
even lower portion of the total costs.
Compared to Scenario 1, Scenario 2 exhibits a lower differential between PG&E's and the CCE's
customer generation rates between 2018 and 2033. After 2033, the price of renewable generation
is expected to undercut the wholesale electricity market for non-RPS supplies, rendering a higher
differential in Scenario 2 than in Scenario 1. With respect to PG&E's rates, this differential will
38 50% of the non-RPS generation for 2018-2028
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continue to follow a similar pattern: positive for all years from 2018 to 2038. And as was the
case in Scenario 1, Scenario 2 enables the CCE to reliably price its average generation rates
lower than those of PG&E.
Figure 17. Scenario 2 Forecast Average CCE Cost and PG&E Rates, 2018-203839
Residential Bill Impacts
Table 9 summarizes the average annual savings for residential customers under Scenario 2. For
the 2018-2038 period, the average annual bill for a residential customer of the Contra Costa
County CCE program will be 8% lower than the same bill under PG&E rates. This is a little less
than, but close to, the bill savings under Scenario 1. Note that these rate impacts assume that a
rate stabilization reserve is funded during the first few years of the CCE’s existence. Thus, even
though a “gap” between the CCE costs and PG&E rates can be seen in Figure 17, the bill savings
in 2018 is zero, as the additional CCE funds are assume to go to the reserve rather than as a
customer bill savings.
39 This chart doesn’t include the reserve fund.
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Table 9. Scenario 2 Savings for Residential CCE Customers
Residential
Monthly
Consumption
(kWh)
Bill with
PG&E ($)
Bill with
Contra
Costa
County CCE
($)
Savings ($) Savings (%)
2018 500 121 121 0 0%
2020 500 129 125 4 3%
2030 500 189 172 17 9%
2038 500 254 225 29 11%
GHG Emissions
Under Scenario 2, we model the Contra Costa County CCE to at least as much carbon-free
generation as PG&E. As in Scenario 1, in years where the assumed renewables would not result
in the CCE halving PG&E’s GHG emissions, we add large hydroelectric generation to the CCE’s
resource portfolio to make up the difference, subject to a 5% minimum supply from market
purchases. In other years when the CCE’s RPS targets are sufficient to provide GHG savings
relative to PG&E, we assume that emissions are further reduced by sourcing 50% of the non-
RPS supply from large hydro. The end result is a portfolio that averages 20% large hydro.
Figure 18 compares the Scenario 2 GHG emissions from 2018-2038 for the Contra Costa County
CCE with what PG&E’s emissions would be for the same load if no CCE were formed. Since
Scenario 2 has a higher renewable generation target (80% by 2030), the hydroelectric generation
necessary to achieve the same GHG emissions reduction is lower. As a result of trading off large
hydro for RPS-eligible energy, GHG emissions in Scenario 2 are the same as Scenario 1 through
2027, after which the CCE's portfolio will produce less than half the GHG emissions compared
to PG&E.
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Figure 18. Scenario 2 Contra Costa County CCE Supply Portfolio (vertical bars) and GHG
Emissions (lines) (“Normal” PG&E Hydro Conditions)
Scenario 3 (Minimum RPS Compliance plus Local Procurement)
Scenario 3 is identical to Scenario 1, save for a greater portion of locally sourced renewables.
Under Scenario 3, local renewables increase annually, reaching 50% of the renewable supply by
2027 and continues at 50% through 2038.
CCE Costs
Figure 19 summarizes the results for this scenario. The vertical bars represent the Contra Costa
County CCE customer rate, and the green line represents the PG&E generation rate. As with
Scenario 1, the non-renewable cost is the largest component of the CCE’s rates, followed by
renewable generation costs. The latter are greater than in Scenario 1 due to the higher prices of
local generation resources. As with previous scenarios, the PCIA exit fee is the third largest
expenditure and it is expected to decrease most years after 2020. As with Scenario 1, the costs
associated with GHG allowance purchases are responsible for a marginally larger percentage of
the CCE's total costs between 2028 and 2038. This is mostly due to the lower share of GHG-free
emissions.
The Scenario 3 differential between PG&E generation rates and Contra Costa County CCE falls
in the middle of Scenario 1 and 2 until 2028. Afterwards, the Scenario 3 differential, decreases
further, pushing it below Scenarios 1 and 2. However, the CCE rates are expected to be lower
than PG&E's generation rates for the entire forecast period, which will allow the CCE to collect
reserve fund contributions annually from 2018 to 2038.
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Figure 19. Scenario 3: Forecast Average CCE Cost and PG&E Rates, 2018-2038
Residential Bill Impacts
Table 10 summarizes the average residential bill impacts under Scenario 3. Between 2018 and
2038, the annual bill for a residential customer of the Contra Costa County CCE program will be,
on average, 6% lower than a corresponding PG&E bill.
Table 10. Scenario 3 Savings for Residential CCE Customers
Residential
Monthly
Consumption
(kWh)
Bill with
PG&E ($)
Bill with
Contra
Costa
County CCE
($)
Savings ($) Savings (%)
2018 500 121 121 0 0%
2020 500 129 125 4 3%
2030 500 189 175 14 7%
2038 500 254 231 23 9%
GHG Emissions
The emissions pattern for Scenario 3 is identical to Scenario 1 due to the equal GHG-free
generation proportion. The only difference is that part of this generation is provided by local
sources. Figure 20 shows the GHG emissions from 2018-2038 for the Contra Costa County CCE
under Scenario 3. Note that GHG emissions from the Contra Costa CCE supply and PG&E
supply are the same as in Scenario 1.
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Figure 20. Scenario 3 Contra Costa County CCE Supply Portfolio (vertical bars) and GHG
Emissions (lines) (“Normal” PG&E Hydro Conditions)
Scenario 4 (Accelerated RPS plus Local Procurement)
Scenario 4 is the same scenario as Scenario 2 but with a more substantial portion of the
generation sourced from local renewable sources: increasing annually and achieving 50% of the
total RPS supply by 2027 through 2038.
CCE Average Costs
Figure 21 summarizes the results for this scenario. The vertical bars represent the Contra Costa
County CCE customer rate, and the green line represents the PG&E generation rate. Under
Scenario 4, the cost for renewables forms the largest component of the CCE’s rates and grows
steadily to account for nearly 60% of the total CCE rate in 2030. Non-renewable generation is
the next largest cost component of the rate, followed by the PCIA exit fee, which is expected to
decrease in most years beginning 2020. As with Scenario 2, the costs for GHG allowance
purchases in Scenario 4 are a smaller portion of total costs because of more RPS power.
The differential between PG&E generation rates and Contra Costa County CCE customer rates
in Scenario 4 is the lowest of the four scenarios between 2018 and 2028. This is because
Scenario 4 has the most expensive supply portfolio, comprised of more locally sources
renewables. However, after 2028, when the price of the renewable generation is expected to be
lower than the wholesale electric market, the differential in Scenario 4 will be higher than the
differential in Scenarios 1 and 3, but lower than Scenario 2. Similar to the other scenarios, the
Contra Costa County CCE rates in Scenario 4 are forecasted to be lower than expected PG&E
generation rates for all years from 2018 to 2038. And as such, this enables the collection of
reserve fund contributions through the CCE's rates in every year of the forecast period.
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Figure 21. Scenario 4: Forecast Average CCE Cost and PG&E Rates, 2017-2030
Residential Bill Impacts
Table 11 summarizes the average residential bill impacts under Scenario 4. Over the 2018-2038
study period, the annual bill for a residential customer of the Contra Costa County CCE program
will be, on average, 4% lower than the same bill under PG&E rates under Scenario 4. Again,
note that these rate impacts assume that a rate stabilization reserve is funded during the first few
years of the CCE’s existence. Thus, even though a “gap” between the CCE costs and PG&E
rates can be seen in Figure 21, the bill savings in 2018 is zero, as the additional CCE funds are
assume to go to the reserve rather than as a customer bill savings.
Table 11. Scenario 4 Savings for Residential CCE Customers
Residential
Monthly
Consumption
(kWh)
Bill with
PG&E ($)
Bill with
Contra Costa
County CCE
($)
Savings
($) Savings (%)
2018 500 121 121 0 0%
2020 500 129 126 3 2%
2030 500 189 182 7 4%
2038 500 254 235 19 7%
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GHG Emissions
The GHG emissions pattern for Scenario 4 is to the same as Scenario 2 due to the scenarios
having the same shares of GHG-free generation; the only difference being that local solar
generation is assumed to replace solar supplies from more distant locations. . Figure 22
compares the GHG emissions from 2018-2038 for the Contra Costa County CCE under Scenario
4 with what PG&E’s emissions would be for the same load were no CCE formed.
Figure 22 Scenario 4 Contra Costa County CCE Supply Portfolio (vertical bars) and
GHG Emissions (lines) (“Normal” PG&E Hydro Conditions)
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Chapter 4: Sensitivity of Results to Key Inputs
In addition to the base case forecast described above, MRW has assessed alternative cases to
evaluate the sensitivity of the results to possible conditions that would have an impact on Contra
Costa County CCE’s technical study. The metric considered to compare the alternative
sensitivity cases to the base case is the differential between the annual average generation rates
for PG&E bundled customers and for Contra Costa County CCE customers over the first ten
years (2018-2028).40 The latter 10 years were not included as they are both uncertain and skew
the average results due to the widening gap between modeled PG&E’s rates and the CCE’s
average cost.
The base-case analysis (Chapter 3 –Scenario 1) was developed as a reasonable and conservative
assessment of the Contra Costa County CCE. In addition to the base case analysis, MRW
analyzed alternative cases to address seven risks: (1) low participation, (2) higher local
renewable power prices, (3) higher renewable power prices, (4) higher natural gas prices, (5)
lower PG&E portfolio costs, (6) higher PCIA charges, and (7) a combination of these six risks
(stress scenario).
Lower Participation Sensitivity
This sensitivity case evaluates the impact of lower participation on the CCE program. Lower
Participation could be due to a higher customer opt-out rates, or if some of the cities included in
the study choose not to participate in the CCE program. If fewer customers join, CCE rates will
generally be higher because about $7 million of annual CCE costs are invariant to the amount of
CCE load. In Lower Participation sensitivity, we assume that the load for the Contra Costa
County CCE is 70% of the potential load.41 Average administration costs in this scenario are
12% higher than in the base case scenario. These higher administration costs don’t have a big
impact on the CCE rates due to the fact that administration costs are a small part of the total CCE
rate (5% in average). The impact of this sensitivity case is to reduce the 2018-2028 average rate
differential by 0.07¢/kWh relative to the base case.
Table 12. Lower Participation Sensitivity Results, 2018-2028
Period 2018-2028 Average Admin
costs (¢/kWh)
Average rate
differential (¢/kWh)
Base 0.45 1.86
Low participation 0.51 1.79
40The Contra Costa County CCE rate includes the PG&E exit fees (PCIA charges) that will be charged to CCE
customers but does not include the rate adjustment for the reserve fund or other possible CCE activities.
41 In the Base case we considered 85% of the potential load.
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Higher Local Renewable Power Prices Sensitivity
This sensitivity case evaluates the impact of higher local renewable power prices on the CCE’s
financial viability. As discussed in Appendix B, in the base case, solar local renewable power
price starts at $68/MWh in 2018 and it increases following the price curve. In the Higher Local
Renewable Power Prices sensitivity, we assume that local renewable prices would be 20% higher
than the base case prices. These higher prices affect only CCE rates for Scenario 3 and Scenario
4 (Scenario 1 and Scenario 2 don’t include local generation), reducing the 2018-2028 average
rate differential by 0.21¢/kWh relative to the base case.
Table 13. Higher Local Renewable Power Prices Sensitivity Results, 2018-202842
Period 2018-2028
Average local
renewable prices
($/MWh)
Average rate
differential (¢/kWh)
Base 69.30 1.57
High local renewable prices 83.20 1.36
Higher Renewable Power Prices Sensitivity
This sensitivity case evaluates the impact of higher renewable power prices on the CCE’s
financial viability. As discussed in Appendix B, in the base case, renewable power prices are flat
in nominal dollars through 2022, based on the assumption that projected declines in renewable
development costs will offset increases associated with the planned expiration of federal
renewable tax credits.43,44 In the Higher Renewable Power Prices sensitivity, we assume that
renewable prices would be flat in nominal dollars through 2022 if it were not for the tax credit
expirations and add the impact of the tax credit expirations to the base case prices. Average
renewable power prices in this scenario are 0-10% higher than in the base case scenario through
2021, about 20% higher in 2021 and 2022, and 30% higher after 2022 when the solar investment
tax credit is reduced to 10%. These higher prices affect both the CCE and PG&E, but they have a
greater effect on the CCE because PG&E has significant amounts of renewable resources under
42 Results for Scenario 3
43 Investment Tax Credit (ITC) which is commonly used by solar developers, is scheduled to remain at its current
level of 30% through 2019 and then to fall over three years to 10%, where it is to remain. The federal Production
Tax Credit (PTC), which is commonly used by wind developers, is scheduled to be reduced for facilities
commencing construction in 2017-2019 and eliminated for subsequent construction.
U.S. Department of Energy. Business Energy Investment Tax Credit (ITC). http://energy.gov/savings/business-
energy-investment-tax-credit-itc; U.S. Department of Energy. Electricity Production Tax Credit (PTC).
http://energy.gov/savings/renewable-electricity-production-tax-credit-ptc
44 The base case forecast would also be consistent with a scenario in which the tax credit expirations are delayed.
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long-term contract. The impact of this stress case is to reduce the 2018-2028 average rate
differential by 0.35¢/kWh relative to the base case.
Table 14. Higher Renewable Power Prices Sensitivity Results, 2018-2028
Average RPS prices
($/MWh)
Resulting average rate
differential (¢/kWh)
Base 53.2 1.86
High renewable prices 65.1 1.51
Higher Exit Fee (PCIA) Sensitivity
PG&E’s PCIA exit fees are subject to considerable uncertainty. Under the current methodology,
PCIA rates can swing dramatically from one year to the next, and this methodology is currently
under review and may be adjusted in the coming years. MRW therefore evaluated a stress case in
which PCIA rates don’t fall after 2018, as anticipated in the base case, but instead remain at 2018
levels through 2028. This increases the 2028 PCIA more than 300% of its base case value. The
impact of this stress case is to reduce the 2018-2028 average rate differential by 0.86¢/kWh
relative to the base case.
Table 15. Higher PCIA Exit Fee Sensitivity Results, 2018-2028
Average PCIA prices
(¢/kWh)
Resulting average
rate differential
(¢/kWh)
Base 1.5 1.86
High PCIA 2.4 1.00
Lower PG&E Portfolio Cost Sensitivity
While changes to natural gas prices and renewable power prices affect both the CCE and PG&E,
dampening the impact on the CCE’s cost competitiveness, reductions to the costs to operate and
maintain PG&E’s nuclear and hydroelectric facilities would provide cost savings to PG&E that
would not be offset by cost savings to the CCE. MRW considered a case in which PG&E’s
overall generation rates are 10% below the base case, driven by reductions to PG&E’s nuclear,
and hydroelectric portfolio costs. Under such a scenario, the 2018-2028 average rate differential
would be reduced by 1.12¢/kWh relative to the base case scenario.
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Table 16. Lower PG&E Portfolio Sensitivity Results, 2018-2038
Average PG&E Rate
(¢/kWh)
Resulting average
rate differential
(¢/kWh)
Base 11.2 1.86
Low PG&E portfolio costs 10.1 0.74
Higher Natural Gas Prices Sensitivity
Natural gas prices have been low and relatively steady over the last few years, but they have
historically been quite volatile and subject to significant swings from local supply disruptions
(e.g., Hurricanes Katrina and Rita in 2005). MRW analyzed a gas price sensitivity case using the
U.S. Energy Information Administration’s High Scenario natural gas prices forecast,45 which is
in average 50% higher than MRW’s base case forecast for the period 2018-2028. Natural gas
price increases affect power supply costs for both Contra Costa County CCE and PG&E;
however, the nuclear and hydroelectric capacity in PG&E’s resource mix makes PG&E less
sensitive than Contra Costa County CCE to changes in natural gas prices. The net effect of
higher natural gas prices is therefore to increase CCE rates relative to PG&E rates46 (i.e., reduce
the average rate differential). Under the sensitivity conditions considered, the 2018-2038 average
rate differential decreases relative to the base case by 1.68¢/kWh.
Table 17. Higher Natural Gas Prices Sensitivity Results, 2018-2028
Average PG&E Rate
(¢/kWh)
Resulting average
rate differential
(¢/kWh)
Base 11.2 1.86
Low PG&E portfolio costs 10.1 0.18
Stress Case and Sensitivity Comparisons
All rate differentials (i.e., the CCE’s competitive positions) are lower in the sensitivity cases than
in the base case scenario for all years from 2018 to 2028 (Table 18). To evaluate a more extreme
scenario, MRW developed a stress case that combines all the sensitivity cases: (1) low
participation, (2) higher local renewable power prices, (3) higher renewable power prices, (4)
higher natural gas prices, (5) lower PG&E portfolio costs, and (6) higher PCIA charges. The
45 U.S. Energy Information Administration. “2015 Annual Energy Outlook,” Table 13
46 For the Scenario 2 and 4 the high gas natural prices case has less negative impact due to the high proportion of
renewable generation.
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2018-2028 average rate differential for this stress case is negative, at -4.08¢/kWh, meaning that
CCE customer costs would exceed PG&E customer costs under this scenario.
Table 18. Stress Test Results, 2018-2028
Resulting average
rate differential
(¢/kWh)
Base 1.86
Stress Scenario -2.3
Figure 23. Difference Between PG&E Customer Rates and CCE Customer Rates Under
Each Sensitivity Case, 2018-2028
Figure 23 shows the difference between the PG&E customer rates and the Contra Costa County
CCE customer rates (including exit fees) in the base case, and in each of the sensitivity scenarios,
for each year from 2018 to 2028. As Figure 23 illustrates, CCE customer rates are lower than
PG&E customer rates in each of the individual sensitivity cases in each year.47 Under the Stress
Scenario case, the rate differential is negative for each year (i.e., CCE rates are higher than
PG&E generation rates).
47 For High Natural Gas Price sensitivity case, in 2023 the rate differential drops following the decrease on PG&E
rate. The decrease on PG&E rate in 2023 under the high natural gas price case is due to an increase on the PCIA.
PCIA is highly sensitive to the natural gas prices.
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The results shown above reflect the Minimum RPS Compliance supply scenario (Scenario 1).
MRW additionally evaluated each sensitivity scenario under the four alternative supply
scenarios: (1) Minimum RPS Compliance, (2) Accelerated RPS, (3) Minimum RPS Compliance
plus Local Procurement, and (4) Accelerated RPS plus Local Procurement. Figure 24 depicts the
average rate differentials for 2018-2028 for each sensitivity case under the four supply scenarios.
Figure 24. Difference Between PG&E Customer Rates and CCE Customer Rates Under
Each Sensitivity Case and Supply Scenario, 2018-2028 Average
Looking at 2018-2028, Scenario 1 (Minimum RPS Compliance) is the least costly scenario for
the CCE, and therefore has the highest rate differential under most of the sensitivity cases
considered.48 Scenario 2 (Accelerated RPS), though still quite competitive with PG&E, fares
slightly worse, with a rate differential approximately 10-20% lower than in Scenario 1 for most
of the sensitivity cases considered. The one exception is the High Natural Gas Price sensitivity
case, in which Scenario 1 has lower results than Scenario 2. This is due to the higher gas-fired
generation content in Scenario 1, which makes the supply portfolio more susceptible to volatility
in natural gas prices than Scenario 2. For most the sensitivity cases, rate differentials for
Scenario 3 are lower than Scenario 1 and Scenario 2. Scenario 4 is the costliest scenario, with
rate differentials much lower than those in Scenario 1, Scenario 2, and Scenario 3.
48 This is only looking at the period 2018-2028. If we consider the period 2018-2038, Scenario 2 would be the least
costly scenario. After 2028 the prices of renewable generation are expected to be lower than the wholesale electric
market, which makes Scenario 2 less costly than Scenario 1 in the period 2028-2038.
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In the stress case, Contra Costa County CCE customer rates exceed PG&E customer rates on
average over the 2018-2028 period for all four scenarios, with the rate differential being highest
in Scenario 4 at -3.8¢/kWh.
Conclusions
Under Scenarios 1 and 2, Contra Costa County CCE customer rates compare quite favorably to
PG&E rates in all years from 2018 to 2038 under all four supply scenarios. Furthermore, under
Scenario (Minimum RPS compliance), Contra Costa County CCE customer rates remain below
PG&E rates under all but the most extreme sensitivity case considered (however at the price of
possible higher GHG emissions). Under the stress case, irrespective of the supply scenario
considered, CCE rates are higher than PG&E rates. While the stress case may appear extreme
given that it involves seven adverse sensitivities simultaneously occurring, cost volatility in the
power industry is well established, and the possibility of adverse conditions arising should be
understood and planned for in any CCE venture.
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Chapter 5: Macroeconomic Impacts
This chapter discusses the job impacts within Contra Costa County for each of the four scenarios.
All four scenarios modeled showed positive economic and job impacts. The mix and amount of
jobs created would depend upon policy decisions made by the CCE board, primarily trading off
the economic stimulus from lower electricity bills versus the direct jobs created by local (higher
cost) renewable energy projects sponsored by the CCE.
To understand just how job impacts can come about, and the extent of those changes (positive or
negative), a brief description of elements associated with the CCE and how they influence the
existing economy is provided.
How a CCE interacts with the Surrounding Economy
The establishment and operation of a CCE creates a new set of spending elements (also referred
to as “demands”) as a community changes the type of electricity generation they want to
purchase, where the new mix of generation is to be located, adjustments necessary for existing
generating assets of the provider utility, and implications on customers’ bills because of retail
rate differentials. Some of these new elements have temporary effects, while others have long-
term effects. Investment in locally sited solar will result in temporary direct creation of jobs
whereas subsequent maintenance will support some on-going direct jobs. Regardless of the
duration, when a direct job is created in a sector, there will be a multiplier response on
“backwardly-linked” jobs with supplier businesses if the supplier is present in the economy. The
new elements include:
Administration – [direct jobs, long-term effect] county staffing, professional-technical
services and I/T-database services
Net Rate Savings (or bill savings) – [long-term effect] county households have an
increase in their spending ability, county commercial and industrial energy customers
experience a reduction in their costs-of-doing business which makes them each more
competitive, garnering more business that requires more employees, and municipal
energy customers can provide more local services which requires more local government
staff.
New Renewable Capacity Investment within County & Surrounding counties –
[direct jobs, short-term, two of the four scenarios]
New Renewable Operations within County & Surrounding counties – [direct jobs,
long-term, two of the four scenarios]
Net Generating Capacity and Operations offsets for PG&E outside of county –
[direct jobs, short & long-term, none since we are not focused on the rest of CA
economy]
To frame expectations around how many direct jobs can be created in the County from the above
CCE elements, consideration must be given to (a) how much of the spending associated with the
CCE scenario is fulfilled by a within county business or resident workforce, and (b) what do
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these locally-fulfilled dollars represent in terms of current annual county business activity (e.g.,
is this a large spending event?).
Job Impacts of Proposed CCE Scenarios
We examine each of the four scenarios for their influence on the County economy and the
economy of the four surrounding counties combined (a ring region comprised of Alameda,
Sacramento, San Joaquin and Solano counties). The basis for including the surrounding counties
is (i) interdependence of the economies in terms of business-to-business transactions (in part due
to proximity) and labor commuting flows (both in and out), as well as (ii) the siting of 50 percent
of the proposed CCE funded small-scale solar projects beyond Contra Costa county. The
scenario structures assume no electric customer participation from beyond Contra Costa County
therefore the proposed bill savings are allocated across customer segments solely within Contra
Costa County.
The possible sources of initial job change in any of the scenarios include:
CCE Administration spending 2018 to 2038 (within Contra Costa County)
Bill Savings less Customer’s expense for on-site solar deployed 2018 to 2038 (within
Contra Costa County)
Investment in small-scale Solar 2018 to 2030 (Contra Costa and the 4-county ring region)
O&M spending on small-scale Solar 2018 to 2038 (Contra Costa and the 4-county ring
region)
Only scenarios 3 and 4 include investment for small-solar projects in Contra Costa County and
the surrounding region of counties. Once each regional economy experiences its initial change
related to any of the above scenario elements, a macroeconomic forecasting tool (the REMI
model49) captures impacts from inter-regional transactions (of commuters, of business sales), and
impacts from changes in Contra Costa County’s relative cost-of-living and cost-of-doing business
resulting from bill savings, and impacts associated with multiplier effects.
Overview of Scenario Effects
It is helpful to understand how the various scenarios “stack up” in terms of the four sources that
will exert an influence on the local economies. Table 19 presents the cumulative (2018 to 2038)
stimuli - bill savings, administrative spending, and where relevant, demands related to
investment, O&M. The amounts are a roll-up of nominal values. Scenario 1 poses the greatest
amount of Rate Savings for county CCE customers ($2,390 million), and Scenario 4 poses the
largest amount of solar investment demand ($827 million) for in-county installations. Ensuing
O&M spending (Scenarios 3 and 4) will increase as the investment demand increases. None of
the displaced renewable capacity by PG&E (investments under the “business-as-usual” or
“without CCE” case) occurs in either Contra Costa or the surrounding 4 counties.
49 Regional Economic Models, Inc. of Amherst, MA. www.remi.com
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Table 19. CCE Scenario Economic Characteristics (2018-2038, Millions of nominal
dollars)50
Scen.
Net Rate savings
County
customers
CCE Small Solar Investment CCE Small Solar O&M
Contra Costa
County
Neighboring
Counties
Contra Costa
County
Neighboring
Counties
1 $2,390 $0 $0 $0 $0
2 $2,251 $0 $0 $0 $0
3 $1,656 $456 $456 $234 $234
4 $614 $827 $827 $375 $375
Figure 25 Figure 25presents the estimated net rate savings for various customer-segments in the
County by CCE scenario. The rate savings benefit accrues foremost to the residential segment,
followed by the Commercial segment. The Municipal segment has fairly constant rate savings
regardless of scenario. In addition to the magnitude of overall net rate savings and local solar-
related business opportunities, this segment distribution across customer segments influences
part of the job impact response (amidst solar investments). Households spend money saved on
electric bills on other consumer basket items, which would include a mix of goods and services;
some local, some imported, which all rely on different jobs at different wages. Commercial or
Industrial electric customers experience a savings as making their operations more cost
competitive, which returns some positive (though not equal across all type of activities) market
share growth (e.g., more sales which means more jobs and other inputs to their operations.)
Municipal segment savings allow the state/local government entity to redirect dollars into other
forms of public spending.
50 Net Rate Savings are net of customer out-of-pocket for on-site solar additions. under scenarios
3 and 4. For the County projects, 25 percent of the investment is paid by Industrial customers, 25
percent by Commercial customers, with the balance funded by outside investors. Small-solar
projects in the surrounding counties are assumed to be funded by outside investors. Under
scenarios 1 and 2 net is equal to gross rate savings.
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Figure 25. Cumulative net Rate Savings in Contra Costa County, Proposed CCE structures
The opportunity for the small-solar investment episode (2018 through 2030), for scenarios 3 and
4, to generate “within region” job requirements is determined by how much of the investment
dollars connect with (procure from) ‘within region’ construction labor and businesses that
provide project components. The allocations of small-solar investment dollars into these two
major types of purchases (with additional breakdown on non-labor expenditures) is done using
the National Renewable Energy Laboratory (NREL) Jobs and Economic Development Impact
(JEDI) small-solar PV JEDI model51 (CA) allocation. As shown in Table 20 for scenarios 3 and
4, no less than 50 percent of the various budgets enlists local workforce, and firms that provide
supplies or services. Manufacturing of solar panels is outside of the 5-county economy but
within region wholesale distributors are assumed to bring “product local.”
51 The Jobs and Economic Development Impact (JEDI) models are user -friendly screening tools that 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. See:
http://www.nrel.gov/analysis/jedi/about_jedi.html
-$500
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
SC1 Sc2 Sc3 Sc4
RESID COMMRCL INDSTRL MUNIC
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Table 20. Local Fulfillment of CCE Budgets (millions of nominal dollars)
CCA
Admin
Solar
Invest
Solar
O&M
CCA
Admin
Solar
Invest
Solar
O&M
Scenario 1 Scenario 3
Budget $316 na na $316 $456 $233
In-County
locally procured $189 na na $189 $234 $146
% capture local 60% na na 60% 51% 63%
Surrounding Counties
locally procured na na na na $234 $146
% capture local na na na na 51% 63%
Scenario 2 Scenario 4
Budget $316 na na $316 $ 827 $375
In-County
locally procured $189 na na $189 $425 $235
% capture local 60% na na 60% 51% 63%
Surrounding Counties
locally procured na na na na $450 $219
% capture local na na na na 51% 63%
Resulting Impacts on Jobs
This section will present several views of the job impacts by scenario. As shown in Table 21,
Scenario 1 yields the largest annual job impact for the County over the interval – the result of the
maximum rate savings under the CCE program. Job impacts are not limited to the direct job
requirements from a CCE but include jobs resulting from multiplier effects and competitiveness
effects. Scenario 4 – with the smallest of net rate savings for the County’s electric customers
poses the largest investment for small-solar across the 5-county economy. This more than
compensates for the reduced role of the rate savings and thus Scenario 4 yields the greatest
annual job gain for the 5-county economy, 941 jobs (compared to Scenario 1 with 731). As the
amount of small-solar investment increases (with subsequent O&M spending to follow), the
percent of job impact that occurs within the surrounding multi-county region increases (Scenario
4 has 44%). The county’s annual job increase under Scenario 4 however is moderated (by 160
jobs) when compared to Scenario 1. This is understood by (i) all CCE customers’ realizing
smaller rate savings when the CCE attempts to invest in local solar, combined with (ii)
commercial/industrial businesses in the County picking up 50 percent of the solar investment
cost. Also, influencing the “surrounding county region” job impact is the fact that a neighboring
economy (the County) is experiencing lower electric bills (regardless of the magnitude) and a
solar installation “boom” – namely, economic stimulating events. This can create a positive
bounce for the surrounding counties on some of the background business (supplier) transactions
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as well as with working-age households who commute into the County (this point is illustrated in
Figure 26) And when the surrounding region is host to its own solar installation boom, this will
engage the Contra Costa County economy as well.
Table 21. Average Annual Employment Impacts 2018 through 2038 (Jobs)
Scenario Contra
Costa
Surrounding
4 Counties
All 5
counties
% in
Region
1 681 50 731 7%
2 638 48 686 7%
3 654 268 922 29%
4 529 412 941 44%
For Scenario 4 (with the smallest net rate savings and the highest local solar-investment/O&M
spend) a time-path of the resulting job impacts is shown in Figure 26. To be clear, the results are
not depicting cumulative job impacts, simply a plot of each year’s resulting impact. After 2030
no more solar installations occur in either region52. The surrounding region remains slightly
buoyed with job impacts due to some continued O&M spending and feedback from the Contra
Costa economy that is still benefitting now from gross rate savings (no more project expenses)
and some O&M spending.
Figure 26. Scenario 4 – Annual Job Impacts, 2018 to 2038
Figure 27 helps explain ‘the dip’ in the above blue series of positive job impacts (for Contra
Costa) between 2024 and 2030. The estimated forecast of net rate savings follows such a
trajectory (becoming negative between 2024 and 2028 when some customers bear a portion of
52 This is because the targeted renewable penetration was met and not new generation is needed by the CCE. If the
study looked further out, then replacement solar would being to have an effect and generate jobs.
0
200
400
600
800
1000
1200
201820192020202120222023202420252026202720282029203020312032203320342035203620372038JobsContra Costa Surr. Region
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the investment cost) and even the local capture on the solar investment comes off a local
maximum in 2020 and a global maximum in 2027 (the latter occurs in the surrounding region as
well).
Figure 27. Scenario 4 – Contra Costa’s “Local” Benefit
Figure 28 shows what contributes to Contra Costa’s job impact under Scenario 4. The dark blue
line is the line from Figure 26. Through 2030 largest influence on the County’s positive job
impacts is the stimulus of solar project investment. Afterwards it is the role of net Rate Savings
exerted through the customers’ roles in the local economy that creates local jobs.
Figure 28. Scenario 4 – Contra Costa Job Impact by Source
-$80,000,000
-$60,000,000
-$40,000,000
-$20,000,000
$0
$20,000,000
$40,000,000
$60,000,000
$80,000,000
$100,000,000
$120,000,000
$140,000,000
201820192020202120222023202420252026202720282029203020312032203320342035203620372038net rate savings INV/OM/Admin
-400
-200
0
200
400
600
800
1000
1200
201820192020202120222023202420252026202720282029203020312032203320342035203620372038Thousandsfrom INV/om/Admin from net Bill Savings total
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A look at two points in the policy interval illustrates of the types of jobs that comprise the impact
results. In 2020 there are 704 additional jobs (when solar investment is at a maximum with little
of the net rate savings realized) and 2038, 989 additional jobs in the County (after the investment
hang-over is past and only a small influence is exerted through O&M and administrative
spending, and the County economy is still experiencing a ramp up of rate savings). Figure 29
shows a pattern and an amplitude for each of the snapshot years that is indicative of the major
CCE influence on the County’s industry base. In 2020 there was approximately $26 million of
local benefit for the County based on the scenario’s structure ($53 million was
invest/O&M/admin spend, and -$26 million of early stage dis-benefit via net rate savings). By
2038 the local benefit to the County was $157 million ($29 million as O&M/admin spend and
$128 million as gross rate savings). These amounts can be approximated looking back at Figure
27 and summing the height of the orange and blue points for 2020 and again for 2038.
In 2020, county job additions are explained foremost by the predominant effect emanating from
the CCE scenario – namely solar project investment and program administration (net rate savings
are negative at this point as a result of C/I customers paying for part of the solar investment
cost). So, jobs occur in Construction, in State/Local Government, in Professional Technical
Services, and with Wholesale suppliers. Project developer overhead payments (part of the
investment cost) is why job additions are showing for Management of Companies and
Enterprises. But not all of the job additions in these sectors are directly related to solar
installations. Some of these – as well as jobs gains in other non-investment sectors like health
care, and food establishments, and retail- are the result of the initial labor income gains
(construction paychecks) which drives added household spending (the induced stage of
economic multiplier effects), and some are the result of increases in “within county” business-to-
business transactions and elevated business needs from the adjacent region (the indirect stage of
multiplier effects.)
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Figure 29. Scenario 4 - Jobs added Among Contra Costa Sectors, 2020 and 2038
In 2038 (the orange series) the predominant ‘economy’ effect from the CCE is the net rate
savings with a majority benefitting the residential segment. Households will redirect these
savings into additional household spending (e.g. health care, retail, food establishments). But the
municipal segment receives savings as well which drives additional public spending and requires
some growth in staff in addition to the local government staff to administer the CCE (an average
of 23 administrative staff). Commercial and industrial sectors also experience some job
increases as their bill savings improve their bottom lines and grow their respective market shares
for business. The pronounced gain in local government jobs is more than the (averaged) 23 staff
mentioned above. By 2038 the County will have retained a significant number of its working-
age residents that would otherwise out-migrated (under the business-as-usual case) due to a
combination of relative employment opportunities and inflation adjusted wages. The CCE
activity creates job opportunity, mitigates in-county inflation (vis a vis bill savings) so there is
real wage appreciation, and helps stem the tide of out-migration of key working-age cohorts.
This further bolsters the positive population growth the County was forecast to have (under the
BAU case), and local government spending (and staffing) increase on a per capita basis. In
addition, the S/L government activity increases as the productive capacity of the County grows
(in terms of dollars of gross regional product). The Construction sector posts strong job increases
but now it is more the response to growth in the County (due to CCE influences) and this sector
is key during investment (for both residential and non-residential structures) responses to close
the gap between actual and optimal capital requirements in a growing economy.
0 50 100 150 200 250
Forestry, Fishing, and Related Activities
Mining
Utilities
Construction
Manufacturing
Wholesale Trade
Retail Trade
Transportation and Warehousing
Information
Finance and Insurance
Real Estate and Rental and Leasing
Professional, Scientific, and Technical…
Management of Companies and Enterprises
Administrative and Waste Management…
Educational services; private
Health Care and Social Assistance
Arts, Entertainment, and Recreation
Accommodation and Food Services
Other Services, except Public Administration
Local Govt
2038 2020
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Figure 30 shows for 2020 which of the affected sectors’ job increases (a total of 704 added jobs)
are due to direct involvement (blue bars) with some aspect of the CCE and which are the result
of subsequent economic responses. The gray line series is read off the right-hand axis and
indicates the annual pay quality (nominal and with benefits) of a job in a specific sector. The
Construction jobs have annual earnings of $90,000, the Local Government positions
approximately $112,000, Wholesale trade $115,000, Retail trade $46,000, Professional
Technical Services $90,000 and Management of Enterprises (solar developer overhead)
$189,000.
Figure 30. Scenario 4 – Contra Costa Job Creation by Sector,
Impact Stage & Pay-scale, 2020
$-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
$160.00
$180.00
$200.00
0
50
100
150
200
250
Forestry, Fishing, & Rel. ActivitiesMiningUtilitiesConstructionManufacturingWholesale TradeRetail TradeTransportation & WarehsgInformationFinance & Insur.Real Estate & Rental-LeasingProfessl, Scientific, & Tech SrvcsMngmnt of Companies & EnterprisesAdmin. & Waste Mngmnt SrvcsEduc. SrvcsHealth Care & Social AssistArts, & RecreationHotels & Food ServicesOther ServicesLocal GovtJob Impact2020 DIRECT 2020 other sources Annual Earnings per Job (thous.)
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Allocation of Earned Income Gains
A majority but not all jobs added in Contra Costa County will be held by the County’s working-
age resident households. The same is true for jobs added in the 4-county surrounding region.
Which means the household spending effects from the take-home pay on the above impacted
jobs occur where the worker resides. The above job impacts are measured by place-of-work.
The commuter from another county registers the induced effects of their earned income on a
place-of-residence basis.
Again, we focus on Scenario 4 in the year 2020 (year of maximum investment activity that is
split 50:50 across both regions). Before we even allocate the impacts across the County
boundary, it is helpful to reveal the broad commuting propensity (this is not industry-specific but
rather across all activities within an economy) for these two interconnected regions. These
relationships are captured in county data on personal (earned) income flows and the journey-to-
work data – both federally collected. Table 22 shows the extent of linkage on earned income
generated in one region and where its workers reside.
Table 22. Earnings-Commuter Reliance between Contra Costa County and the
Surrounding region
Earnings Place-of-Work
Contra Costa Surrounding
region Worker resides Contra Costa 79% 8.5%
Surrounding Counties 15% 73%
Elsewhere 6% 18%
100% 100%
Based on each of the model region’s reliance on jobs situated beyond their border there will be
“earned income” imported for both Contra Costa and the Surrounding region since both
economies experience job increases under the CCE activity. For workplace earnings generated
in Contra Costa County, 15 percent is earned by residents of the surrounding counties (we ignore
the elsewhere since it is not part of our macroeconomic consideration). Likewise, of workplace
earnings generated in the surrounding counties region, 8.5 percent is by commuters from Contra
Costa County. Table 23 shows for 2020 the extent of extra jobs and earnings that will be held by
a worker who resides in the other region. Of the 704 jobs added in Contra Costa County in 2020,
83 of these jobs (and $7 million of earnings) belong to commuters from the adjacent region. Of
the 584 jobs added in the surrounding region in 2020, 41 of these jobs (and $4 million of
earnings) belong to commuters from Contra Costa County.
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Table 23. Scenario 4 - Earnings Impact by Place-of-Residence, 202053
Scenario 4, Year 2020 Place-of-Work
Contra Costa
County
Surrounding
region
Job impact 704 584
Earnings impact $48 million $42 million
Earnings per Job $86,290 $87,560
% Commuter earnings (Surrounding counties) 15% na
% Commuter earnings (Contra Costa) na 8.5%
Impact Commuter earnings for Surrounding counties $7 million na
Impact Commuter earnings for Contra Costa na $4 million
Equiv. # of Surrounding County Commuters 83 na
Equiv. # of Contra Costa Commuters na 41
Last, a high-level decomposition of the job impact result in the County is shown in Figure 30 for
the scenario 1 (the highest customer savings, no investment in local solar capacity) and scenario
4. Under Scenario 1 the County realizes most job creation through the effects of rate savings on
the County’s economy. This response is 3.5-fold of what Scenario 4 would show as a job impact
from rate savings. Yet Scenario 4 exhibits a more than 5-fold job creation impact from the
combined investment/O&M/administration effects. Including job creation impacts in the
adjacent region of the 4-surrounding counties, scenario 4 produces over 200 more jobs (average
annual) than Scenario 1. This is predominantly explained by the surrounding region being the
location for 50 percent of the small-solar investment that the CCE might choose to fund.
53 Earnings per Job are weighted estimates.
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Figure 30. Average Annual Job Impact in Contra Costa County by Source
68
613
681
731
358
171
529
941
0
100
200
300
400
500
600
700
800
900
1000
INV?/Admin_OM net Energy Savings All fx 5-county economyJobs
Scenario 1 Scenario 4
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Chapter 6: Other Risks
Aside from the risks identified above, the CCE or the political jurisdictions that are part of the
CCE could be at risk for several other reasons. This section addresses some of those risks, which
are summarized in Table 24.54
Table 24. Summary of CCE Risks
Risk Magnitude Mitigation
Financial Risks to CCE Members Low Keep CCE JPA’s financial obligations
separate from jurisdiction’s/
Procurement-Related Risks (i.e., can’t
meet rate or GHG targets) Medium-low Enter into balanced portfolio of power
contracts
Legislative and Regulatory Risks High Monitor and advocate at legislature and
CPUC
PCIA Uncertainty High Establish rate-stabilization fund to
account for volatile PCIA
PCIA Policy
Uncertainty High Monitor and advocate at legislature and
CPUC
Availability/price of low-carbon
resources Medium Enter into balanced portfolio of power
contracts
Bonding Risk Low Monitor and advocate at CPUC
Financial Risks to CCE Members
A CCE is effectively an association of various political subdivisions. The formation documents
for the CCE define the rights and responsibilities of each member of the CCE. Given the large
number of political subdivisions that might participate in a Contra Costa County CCE, MRW
assumes that the Contra Costa County CCE would be formed under a Joint Powers Authority, in
much the same way as MCE Clean Energy and Sonoma Clean Power.
The CCE will ultimately take on various financial obligations. These include obtaining start-up
financing, establishing lines of credit, and entering into contracts with suppliers. Because a CCE
will take on such financial obligations, it is likely very important to the prospective member
political subdivisions that the financial obligations of the CCE cannot be assigned to the
members.
54 Note that this section does not provide legal opinion regarding specific risks , especially those related to the
formation or the structure of the Joint Powers Authority under which MRW assumes the CCE will be established.
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As a result, it is critical that the Joint Powers Authority and any other structuring documents are
carefully drafted to ensure that the member agencies are not jointly obligated on behalf of the
CCE (unless a member agency chooses to bear such obligations). The CCE should obtain
competent legal assistance when developing the formation documents.55
Procurement-Related Risks
Because a CCE is responsible for procurement of supply for its customers, the CCE must
develop a portfolio of supply that meets the resource preferences of its customers (e.g., ratio of
renewable versus non-renewable supply) while controlling risks (e.g., ratio of short-term versus
long-term purchase agreements) and meeting regulatory mandates (e.g., resource adequacy and
RPS requirements). Thus, it is tempting to assume that customers would prefer a fully hedged
supply portfolio. However, such insurance comes at a cost and a CCE must be mindful of the
potential competition from PG&E. Thus, the CCE’s portfolio must be both flexible while
meeting the needs of its customers.
The CCE will likely need to negotiate a flexible supply arrangement with its initial set of
suppliers. Such an arrangement is important since the CCE’s loads are highly uncertain during
CCE ramp-up. Without such an arrangement, the CCE faces the risk of either under- or over-
procuring renewable or non-renewable supplies. Excessive mismatches between supply and
demand of these different products would expose the CCE’s customers to major purchases or
sales in the spot markets. These spot purchases could have a major impact on the CCE’s
financials.
The CCE will by necessity have to procure a certain amount of short-term supplies. These short-
term supplies bring with them price volatility for that element of the supply portfolio. While this
volatility is not unexpected, the CCE must be mindful that such volatility could increase the need
for reserve funds to help buffer rate volatility for the CCE’s customers. Funding such reserve
funds could be challenging in this time of low gas prices (resulting in high PCIA charges).
The CCE will be entering the renewable market at an interesting time. While all LSEs must meet
the expanded RPS targets by 2030, at least the IOUs are currently over-procured relative to their
2020 RPS targets. Whether the IOUs will attempt to sell off some of their near-term renewable
supplies is unknown. However, if the IOUs believe that this is a good time to acquire additional
renewables, the CCE could face stiff competition for renewable supplies, meaning that the green
portfolio costs for the CCE might be higher than expected.
Finally, it should be noted that as greater levels of renewables are developed to meet the State’s
very aggressive RPS goals, it is possible that the traditional peak period will change. Adding
significant amounts of solar could depress prices during the middle of the day. This could result
in the need to try to sell power to out-of-state market participants during the middle of the day,
possibly even at a loss. It could also result in the curtailment of renewable resources (even
55 Cities such as El Cerrito and Benicia have conducted legal analyses when they were considering joining MCE.
which should also be consulted.
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resources owned or controlled by the CCE). This could force the CCE to acquire greater levels of
renewable supplies, thereby increasing costs.
Legislative and Regulatory Risks
As noted above, the CCE must meet various procurement requirements established by the state
and implemented by the CPUC or other agencies. These include procuring sufficient resource
adequacy capacity of the proper type and meeting RPS requirements that are evolving.56
Additional rules and requirements might be established. These could affect the bottom line of the
CCE.
PCIA Uncertainty
Assembly Bill 117, which established the CCE program in California, included a provision that
states that customers that remain with the utility should be “indifferent” to the departure of
customers from utility service to CCE service. This has been broadly interpreted by the CPUC to
mean that the departure of customers to CCE service cannot cause the rates of the remaining
utility “bundled” customers to go up. To maintain bundled customer rates, the CPUC has
instituted an exit fee, known as the “Power Charge Indifference Adjustment” or “PCIA” that is
charged to all CCE customers. The PCIA 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.
Even though there is an explicit formula for calculating the PCIA, forecasting the PCIA is
difficult, since many of the key inputs to the calculation are not publicly available, and the results
are very sensitive to these key assumptions. For PG&E, the PCIA has varied widely; for
example, at one time the PCIA was negative.
Current CCEs have chosen to have customers bear the financial risk associated with the level of
exit fees they will pay to PG&E. Thus, for a customer taking CCE service to be economically
better off (i.e., pay less for electricity), the sum of the CCE charges plus the PCIA must be lower
than PG&E’s generation rate.
This risk can be mitigated in two ways. First, as discussed in more detail elsewhere, a rate
stabilization fund can be created. Second, the CCE can actively monitor and vigorously
participate in CPUC proceedings that impact cost recovery and the PCIA.
Impact of High CCE Penetration on the PCIA
Currently, the PCIA calculation is based on the cost and value of a utility's portfolio, without
regard to how much of that portfolio is to be paid for by bundled customers and how much by
Direct Access (DA) and CCE customers. As such, the PCIA is not affected by the number of
DA/CCE customers.
56 Rules to establish RPS requirements under the new 50% RPS mandate are currently being debated at the CPUC.
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Currently, for bundled customers the rate impacts associated with fluctuating PCIAs are
relatively small, but this will change as the number of DA/CCE customers grows. At some point,
bundled customers' rates may experience marked volatility as the impacts of the annual PCIA
rate swings reverberate to bundled rates. This may be unacceptable to ratepayer advocates and
the Commission.
The PCIA rate volatility in part reflects changes to the utilities’ generation costs, which is
appropriately reflected in bundled customers’ rates. But, often to a large degree, it reflects
changes to the market price benchmark, which should not be relevant to bundled customer rates.
For example, for a utility with flat RPS costs, a reduction to the market price benchmark for
renewable power would increase the RPS-related PCIA, which would reduce bundled rates, even
though there was no change in RPS costs. This could also happen in the reverse direction,
increasing bundled rates when there is no increase in underlying generation costs.
Once DA/CCE load gets large enough that there are real stranded contracts, we suspect that the
Commission is going to look much more closely at the value of these stranded contracts (and
how to get the most value for them).
Impact of High CCE Penetration on Low-Carbon (Hydro) Resources
Virtually all the CCEs forming in California include carbon reduction as a goal. As the analysis
has shown, CCEs will likely need to purchase both RPS-eligible power and other carbon-free
power to meet their goals, namely large hydropower. This has been the approached used by
MCE and Peninsula Clean Power, who both beat PG&E’s GHG emissions rate through contracts
for hydropower. This increased demand for carbon-free hydropower a can change the “supply-
demand” balance and in theory increase the cost of these resources. To address this risk, the
Contra Costa County CCE should consider locking in longer-term contracts for non-RPS eligible
resources early in the process so as to guarantee their availability in the longer term when there
could be greater demand for them.
Bonding Risk
Pursuant to CPUC Decision 05-12-041, a new CCE must include in its registration packet
evidence of insurance or bond that will cover such costs as potential re-entry fees, specifically,
the cost to PG&E if the CCE were to suddenly fail and be forced to return all its customers back
to PG&E bundled service. Currently, a bond amount for CCEs is set at $100,000.
This $100,000 is an interim amount. In 2009, a Settlement was reached in CPUC Docket 03-10-
003 between the three major California electric utilities (including PG&E), two potential CCEs
(San Joaquin Valley Power Authority and the City of Victorville) and The Utility Reform
Network (TURN) concerning how a bonding amount would be calculated. The settlement was
vigorously opposed by MCE and San Francisco and never adopted.
Since then, the issue of CCE bond requirements has not been revisited by the CPUC. If it is, the
bonding requirement will likely follow that set for Energy Service Providers (ESPs) serving
direct access customers. This ESP bond amount covers PG&E’s administrative cost to
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reintegrate a failed ESP’s customers back into bundled service, plus any positive difference
between market-based costs for PG&E to serve the unexpected load and PG&E’s retail
generation rates. Since the ESP bonding requirement has been in place, retail rates have always
exceeded wholesale market prices, and thus the ESP’s bond requirement has been simply the
equal to a modest administrative cost.
If the ESP bond protocol is adopted for CCEs, during normal conditions, the CCE Bond amount
will not be a concern. However, during a wholesale market price spike, the bond amount could
potentially increase to millions of dollars. But the high bond amount would likely be only short
term, until more stable market conditions prevailed. Also, it is important to note that high power
prices (that would cause a high bond requirement) would also depress PG&E’s exit fee and
would also raise PG&E rates, which would in turn likely provide the CCE sufficient headroom to
handle the higher bonding requirement and keep its customers’ overall costs competitive with
what they would have paid had they remained with PG&E. As discussed above, JPA member
entities would not be individually liable for any increase in the bond amount.
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Chapter 7: Comparative Analysis of CCE Options
Having the County and its cities form its own JPA and CCE Program is not the only possibility
for CCE participation. First, the Counties and/or its cities may join Marin Clean Energy (MCE).
In fact, 5 cities in the County—El Cerrito, Lafayette, Richmond, San Pablo, Walnut Creek—are
already members of MCE. These cities joined in 2015 and 2016, and have full standing on
MCE’s Board of Directors. Second, the County and/or its cities could possibly join the East Bay
Community Energy (Alameda County) CCE. While this CCE has not formally been formed—the
Alameda County Board of Supervisors and the respective city Councils are currently taking up
the matter—the Alameda CCE Steering Committee is aiming to have the JPA board seating in
January 2017, with delivery of power beginning in late 2017. Furthermore, the County and each
city need not joint one or other CCE en masse, but instead can join one or the other CCEs
individually (or neither).
This chapter presents the benefits and drawbacks of joining either MCE or EBCE, forming a new
CCE with the County and its cities (which has been the focus of most of the analysis in this
report), or remaining with PG&E. This chapter considers the rate-competitiveness, GHG
reduction, local economic development, local control and governance, cost risks, and CCE
formation timing of each option. Some of the benefits may depend upon how much of the
County chooses which path. Each community chooses for itself; thus, it is perfectly reasonable to
have some join MCE, some join EBCE, and others remain on PG&E service. To the extent that it
matters, this will be highlighted in the sections that follow.
Note that MRW & Associates are not attorneys, and that the MCE and EBCE JPA agreements
are legal documents. Therefore, nothing herein should be interpreted as a legal opinion – only an
informed lay-reading of the documents. MRW would strongly recommend that Contra Costa
County and any city considering becoming a member of MCE or EBCE have its counsel conduct
a thorough review of the respective JPA and related documents prior to committing to a CCE.
Table 25, below summarizes our results. While it is desirable to quantify some (or all) of the
criteria, to do so would be an exercise in false precision. First and foremost, two of the potential
CCE options are with entities which, while potentially viable, do not exist. Without power
contracts, portfolios or procurement guidelines and policies, it would be unwise to claim that
EBCE or a potential Contra Costa-only CCE would have rates or greenhouse gas emissions
higher or lower than the other. Comparisons against MCE can be somewhat more reasonably
asserted; however, its stated goals—greater renewable energy content, lower greenhouse gas
emissions, local generation, and comparable rates—are nearly identical to those stated by EBCE,
so at to make long-range rate and emissions distinctions immaterial. This is in contrast to PG&E,
whose power portfolios, procurement plans and costs are readily available through various
filings and applications it has made before the CPUC. Thus, the qualitative comparisons
provided in the table do not provide sharp distinctions between the CCE options. All these
options are expected to provide similar rates and GHG emissions, with differences arising from
variations in the priorities and procurement decisions of the individual governance boards. What
truly distinguish these options are primarily governance options (i.e., in-county only versus
shared with other entities) and the amount of risk assumed (i.e., developing or signing on with a
new CCE versus joining one with a record of satisfactory performance).
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Each of the lines on the table are discussed in greater detail in the sections that follow.
Table 25. Comparison of Contra Costa CCE Options
Criterion Form CCCo
JPA Join MCE Join EBCE Stay with
PG&E
Rates Likely lower Likely Lower Likely Lower Base
GHG Reduction Potential Over
Forecast Period Some Some Some Base
Local Control/Governance Greatest Some Greater None
Local Economic Benefits Greatest Some Greater Minimal
Start Up Costs/Cost to Join Low, but
greater risk57 None
Unknown, but
likely to be
none
None
Level of Effort Greatest Minimal Greater None
Program Risks Greatest Minimal Some Base
Timing (earliest) Mid-Late-
2018 Late-2017 Mid-2018 N/A
Rates
In general, any of the three CCE options can result, in the long run, with rates that are at or
slightly below those of PG&E. This is not to say that in some years PG&E’s rates may be lower,
or that one CCE would consistently have rates that are lower than the others. Rather, given that a
CCE’s rates are a function if its communities’ values—amount of local renewable generation,
promotion of energy efficiency or distributed generation, overall rate minimization— and that
two of the three CCEs being compared do not yet exist, let alone have rate or procurement
57 Start-up costs provided by the County or others are likely to be reimbursed by the JPA.
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policies, MRW cannot assert that one CCE option will have lower rates that the other two. Both
MCE and EBCE have commitments to higher-cost local renewable development, which suggest
that they are willing to trade off somewhat lower rates for other benefits. A Contra Costa CCE
that focuses more on rate reduction could in principle offer marginally lower rates than the other
two.
GHG Reduction
For climate action planning and reporting purposes, the amount of GHG reduction that can be
attributed to a CCE formation is a function of the difference between the average GHG
emissions from PG&E and that of the CCE. PG&E’s power portfolio is already relatively
“clean,” with large fractions coming from not only qualifying renewables but also nuclear power
(through 2024) and large hydroelectric generators. As Table 26 shows, 59% of PG&E’s 2015
power came from GHG-Free resources. This number would be closer to 67% GHG-free but for
the poor hydroelectric generation due to the ongoing drought.58 Therefore, for any CCE to have a
reduced average carbon footprint requires not only the same or greater amount of qualifying
renewable generation, but additional sources of GHG-free generation.
Table 26. PG&E and MCE Power Content (2015)
PG&E 2015 MCE 2015
Eligible renewable 30% 56%
Large Hydro 6% 12%
Nuclear 23% 0%
GHG-Free subtotal 59% 68%
Unspecified/Market 17% 25%
Natural Gas 25% 12%
Fossil subtotal 41% 32%
An approach taken by some of the currently operating Northern California CCEs is to (a) use
more qualifying renewable generation than PG&E, and (b) contract with and use power from
large hydroelectric resources. This is shown in MCE’s power content mix, and to the extent
possible, what was modeled here for Contra Costa County and for MRW’s study of an Alameda
County CCE.
Given that both MCE and EBCE have made GHG reductions a very high priority, one can
reasonably assume that either will have some GHG-emissions benefit relative to PG&E, but
there is no concrete rationale to assume that either MCE or EBCE will have a significantly-lower
GHG emissions rate than the other.
58 However given climate change, one can sensibly argue that the lower-than-historic-average hydroelectric output
in California seen over the past few years may be more predictive than the historical average.
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Local Economic Benefits
As noted earlier in the report, the amount of local economic benefits is a function of rate
reduction and local construction and CCE staffing. The number of local renewable energy
projects will be a function of at least two factors. The first is any cost competitiveness advantage
of renewable resources in the County; i.e., others will want to build renewable generation in the
County because of cost advantages (including interconnection ease). Second, local generation
development will be fostered by a preference for local generation by the CCE serving Contra
Costa County. While all three CCE options have expressed a preference for “local” renewables,
what the extent of “local” is will contribute to Contra Costa development. MRW would expect
that a Contra Costa CCE would have the greatest interest in developing in-county renewables
and thus could potentially have the greatest positive economic impact. Teaming with either of
the other CCEs would dilute the interest. Given the particularly strong interest of the EBCE
group in local renewables, the notion that “local” might encompass the whole “East Bay,” and
the fact that Contra Costa cities might have greater say in the formation of generation polities
with a new group like EBCE than a more established one like MCE all suggest that EBCE might
be more responsive in developing in-county renewables than MCE.
Contra Costa County makes up but a small fraction of PG&E’s service area. While PG&E’s local
community engagement is admirable, it cannot focus on the County in a way that a smaller CCE
can. As such, any of the three CCE scenarios will likely result in greater local economic benefits
than remaining with PG&E.
CCE Governance: Voting
Per its current proposed JPA, EBCE would have a two-stage vote. Under most circumstances,
each board member (each representing a single entity) would have one vote, regardless of his or
her entity’s size. That is, both Oakland and Piedmont would have an equal vote. In the event of
a non-unanimous affirmative vote, three cities can call for a weighted vote. In that case, each
Representative Board Member’s vote would be weighted according to the size (in kilowatt-
hours) of the entity being represented. These two voting shares are shown in Table 27.
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Table 27. EBCE Voting Shares, With and Without Contra Costa County
Simple Voting Load-Weighted Voting*
Alameda Only Alameda +
Contra Costa
Alameda Only Alameda +
Contra Costa
Oakland 7.1% 3.4% 24.8% 16.4%
Fremont 7.1% 3.4% 16.2% 10.7%
Hayward 7.1% 3.4% 10.1% 6.6%
Berkeley 7.1% 3.4% 8.5% 5.6%
Pleasanton 7.1% 3.4% 6.6% 4.3%
San Leandro 7.1% 3.4% 6.4% 4.2%
Livermore 7.1% 3.4% 6.2% 4.1%
Unincorporated Ala. 7.1% 3.4% 6.4% 4.2%
Other Alameda Cities 42.9% 20.7% 14.9% 9.9%
Alameda Total 100.0% 48.3% 100.0% 66.0%
Unincorporated C.C.
3.4%
8.4%
Concord
3.4%
4.8%
Pittsburg
3.4%
4.3%
Antioch
3.4%
3.4%
San Ramon
3.4%
3.0%
Brentwood
3.4%
2.0%
Danville
3.4%
1.6%
Martinez
3.4%
1.3%
Pleasant Hill
3.4%
1.3%
Oakley
3.4%
1.0%
Orinda
3.4%
0.9%
Hercules
3.4%
0.7%
Pinole
3.4%
0.6%
Moraga
3.4%
0.4%
Clayton
3.4%
0.3%
Contra Costa Total N/A 51.7% N/A 34.0%
*Only in cases where called upon by 3 Board Members
As noted in Table 28 if EBCE consisted of Alameda County alone, the combination of the three
largest entities (Oakland, Fremont, and Hayward) could carry the weighted vote. If all of Contra
Costa county joined EBCE, then it would take the six largest entities (Oakland, Fremont, and
Hayward plus Berkeley, Concord and Unincorporated Contra Costa county) to carry the vote.
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Table 28. EBCE Minimum Cities Needed to Carry Weighted Vote
Alameda Only 3 cities (Oakland, Fremont Hayward)
Alameda +
Contra Costa
6 cities (Oakland, Fremont, Hayward,
Unincorporated CC, Berkeley, Concord)
MCE’s voting structure differs from EBCE’s in two important ways. First, each board member’s
vote is a weighted. Half of each board member’s weighting is equal to his or her entity’s share
of MCE’s total load. The other half is an equal share for each entity. Thus, if a community is
one of 26 members representing 18% of MCE’s load, the board member’s vote would be 10.9%
(18%x(1/2) + (1/26)x(1/2)= 9% + 1.9% = 9.9%) Second, multiple entities have the option to be
represented by a single board member. For example, Napa County and all the towns/cities
within the County are represented by a single board member. While this may dilute the voting
share of each entity represented by the single board member, it allows for less administrative
burden on the represented entities and “streamlines communication and policy setting.”
Table 29 shows what the voting shares might be if all the Contra Costa communities joined MCE
and each claimed its own board member. Together, the Contra Costs communities would
represent 47.4% of MCE’s load and have a total 42.9% of the voting share.
Table 29. MCE Voting Shares With Each Contra Costa Community Having Its Own
Board Member
VOTING SHARES Load
Share
Entity
Share
Voting
Share
Antioch 4.8% 2.6% 3.7%
Brentwood 2.7% 2.6% 2.6%
Clayton 0.4% 2.6% 1.5%
Concord 6.7% 2.6% 4.6%
Danville 2.3% 2.6% 2.4%
Hercules 1.0% 2.6% 1.8%
Martinez 1.8% 2.6% 2.2%
Moraga 0.6% 2.6% 1.6%
Oakley 1.5% 2.6% 2.0%
Orinda 1.3% 2.6% 1.9%
Pinole 0.8% 2.6% 1.7%
Pittsburg 5.9% 2.6% 4.3%
Pleasant Hill 1.8% 2.6% 2.2%
San Ramon 4.1% 2.6% 3.4%
Unincorporated Contra Costa
County
11.7% 2.6% 7.1%
TOTAL CONTRA COSTA COUNTY 47.4% 38.5% 42.9%
Rest of MCE 52.6% 61.5% 57.1%
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Table 30 shows what the voting and load shares might be if all or 1/3 of the Contra Costa
communities joined MCE but opted to be represented by a single board member. In these cases,
the entity share would be low—4%—while the load share would remain pro-rata, resulting in
somewhat lower overall Contra Costa representation.
Table 30. MCE Voting Shares With Contra Costa Communities Sharing a
Single Board Member
VOTING SHARES
Load
Share
Entity
Share
Voting
Share
All of Contra Costa represented by
1 Board Member 47.4% 4% 25.7%
Rest of MCE 52.6% 96% 74.3%
1/3 of Contra Costa load joins and
is represented by 1 Board Member 23.1% 4% 13.5%
Rest of MCE 76.9% 96% 86.5%
CCE Governance: Other
The proposed EBCE JPA Agreement also calls for a formal Community Advisory Committee
(Section 4.9). The relevant section states that the Committee:
“shall be to advise the Board of Directors on all subjects related to the operation of the
CCA Program … with the exception of personnel and litigation decisions. The
Community Advisory Committee is advisory only, and shall not have decision-making
authority… The Board shall appoint members of the Community Advisory Committee
from those individuals expressing interest in serving, and who represent a diverse cross-
section of interests, skill sets and geographic regions.”
The Chair of the Community Advisory Committee will serve as a non-voting ex officio member
of the EBCE Board of Directors.
MCE has no analogous official community advisory committee originating from its JPA
agreement. Nonetheless, there is a “Community Power Coalition” that provides input to MCE
(see, https://www.mcecleanenergy.org/community-power-coalition/). The Coalition works “on a
variety of issues ranging from local renewable energy project development – like MCE Solar
One in Richmond – to outreach for MCE’s Spanish-speaking constituents, to environmental
justice and consumer protection issues affecting MCE’s low-income customers.”
The recitals to EBCE’s JPA agreement lay out what can be described as its envisioned values.
Besides offering competitive rates and lowering greenhouse gasses, this includes (Recitals,
Section 6):
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Establishing an energy portfolio that prioritizes the use and development of local
renewable resources and minimizes the use of unbundled renewable energy credits;
Promoting an energy portfolio that incorporates energy efficiency and demand response
programs and has aggressive reduced consumption goals;
Demonstrating quantifiable economic benefits to the region (e.g. union and prevailing
wage jobs, local workforce development, new energy programs, and increased local
energy investments);
Recognize the value of workers in existing jobs that support the energy infrastructure of
Alameda County and Northern California. The Authority, as a leader in the shift to a
clean energy, commits to ensuring it will take steps to minimize any adverse impacts to
these workers to ensure a “just transition” to the new clean energy economy;
Delivering clean energy programs and projects using a stable, skilled workforce through
such mechanisms as project labor agreements, or other workforce programs that are cost
effective, designed to avoid work stoppages, and ensure quality;
Promoting personal and community ownership of renewable resources, spurring
equitable economic development and increased resilience, especially in low income
communities;
Provide and manage lower cost energy supplies in a manner that provides cost savings to
low-income households and promotes public health in areas impacted by energy
production; and
Create an administering agency that is financially sustainable, responsive to regional
priorities, well managed, and a leader in fair and equitable treatment of employees
through adopting appropriate best practices employment policies, including, but not
limited to, promoting efficient consideration of petitions to unionize, and providing
appropriate wages and benefits.
Contra Costa communities considering joining EBCE should consider these enunciated values
prior to committing to membership.
Timing and Process to Join/Form
The timing required to serve Contra Costa businesses and residents vary markedly among the
CCE options. The quickest path the CCE service would be to join with MCE. Based on MCE’s
currently Inclusion Period, Contra Costa County and its cities could begin MCE service as early
as late 2017.
The first step for a community to join MCE is for its governing body or representative (e.g., city
manager) to provide MCE a non-binding letter of interest. The entity’s governing body would
then need to adopt a resolution requesting MCE membership; have a first reading of an
ordinance to join MCE; execute a memorandum of understanding between the entity and MCE to
address preliminary data and communication issues; and provide a signed request for PG&E to
provide MCE its load data. These steps would need to occur during MCE’s “inclusion period”
which currently runs from December 1, 2016 through May 31, 2017. Only communities in
Contra Costa County are eligible to request MCE membership during this period.
MCE would then evaluate the impact of the new load on its system. If the net result of adding
the new community is that MCE’s rates would increase, then that community’s membership
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would be tabled until a future date. If the MCE analysis shows that adding the community is
favorable, then the MCE Board would vote to accept (or not) the community into MCE. At that
point, the local ordinance for MCE membership would receive a second reading and adoption.
MCE would them modify its official Implementation Plan to reflect the new community, and
submit the updated plan to the California Public Utility Commission. Once approved (none have
been rejected), the phase-in of community into MCE can occur.
The timing and process to join EBCE is more speculative. While the Steering Committee has
strongly suggested that Contra Costa County entities would be welcome to join in, so far, the
EBCE efforts have been solely aimed at getting the CCE going in Alameda County.
The current (draft) JPA documents states in Section 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 an affirmative vote of a majority of all Directors of the
entire Board satisfying the requirements described in Section 4.12, 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..
Thus, a Contra Costa Community would need to adopt a resolution requesting membership in the
EBCE, the board of Directors of EBCE would have to vote to authorize the applying
community’s membership, followed by the applying entity passing an ordinance to join. The
EBCE can charge the applying entity fee or subject it to other restrictions, although given the
likely receptivity to new East Bay membership, it is doubtful that those fees or restrictions would
be onerous.
Furthermore, given its intent to create a JPA—solely with Alameda County representation—in
January, and the further intent to begin its first phase of service as soon as practicable, 3rd or 4th
quarter 2017, it is unlikely that any Contra Costa County city would be enrolled into EBCE
service prior to the middle of 2018. It is also possible that the EBCE JPA would want to get the
program established with Alameda County members before integrating in members from another
county. In this case, EBCE service to Contra Costa County and its cities might not occur until
2019 or 2020.
Implementing a Contra Costa County only CCE would likely have a time line similar to joining
EBCE. If the County and its cities were committed to this path, it could potentially begin service
as early as 2018. This is consistent with Peninsula Clean Energy, which went from putting out an
RFP for a technical study to phase-1 implementation in 18 months (April 2, 2015 to October 1,
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2016). A more measured timeline would suggest that a new Contra Costa CCE would spend
much of 2017, planning and generating local support, with implementation beginning in late
2018 or 2019.
Costs to Join the CCE
This section discusses direct, non-reimbursable costs to cities for joining either EBCE or MCE.
So far, cities joining MCE have not had to pay for any of the costs incurred by MCE to plan for
or integrate their load. They have often spent on the order of $10,000 to $15,000 for consultants
to evaluate the risks to the city and its residents and businesses that could come from joining
MCE.
As EBCE has not seated its board or set any bylaws, one cannot say if, or how much, EBCE
would charge any Contra Costa cities to join. Given its Steering Committee’s interest in
including Contra Costa into its program, one can assume that it would be minimal or zero.
The start-up costs for a new Contra Costa CCE would be significant—Alameda County has
committed $3.4 million to its effort. However, consistent with other CCEs, these costs would be
initially reimbursed to the County and funding cities by a loan taken out by the CCE’s JPA,
which would in turn be paid down via CCE rates over the initial few years. As such, the only
“cost to join” a Contra Costa CCE felt by any individual city would be indirect at best (i.e., asked
to backstop any CCE loads with the entities’ credit.
Exiting the CCE
MCE’s JPA Section 7.0 lays out the process and ramifications of a MEC member withdrawing
from the JPA. First, an entity may withdraw from the JPA within 30 days of its notification of
joining the JPA, assuming that MCE has not entered into any wholesale power agreements to
serve the entity. (Section 7.1.1.1) After MCE has entered into wholesale power agreements to
serve the entity, the entity may withdraw from MCE, effective the beginning of the JPA’s fiscal
year by giving at least 6 months’ written notice of its intent to withdraw. The withdrawing entity
may be subject to “certain continuing liabilities” as laid out in Section 7.3:
7.3 Continuing Liability; Refund. Upon a withdrawal or involuntary
termination of a Party, 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, it being
agreed that the Party shall not be responsible for any claims, demands, damages,
or liabilities arising after the date of the Party’s withdrawal or involuntary
termination. 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 determin ed 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.
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Neither the precise calculation of the liabilities nor now it would be collected is specified.
The proposed EBCE JPA Agreement contains no language concerning a community’s exit from
EBCE or the JPA.
Remaining With PG&E
Although this study suggests CCE program options would likely produce both environmental
and economic benefits for the jurisdictions included in the study, continuing service with PG&E
remains an option for not only a community but also for any individual or business whose
community has selected CCE service (i.e., each individual account maintains its right to opt-out
of CCE service). There are benefits of remaining with PG&E, even at a community level. First,
remaining with PG&E takes no city action. Thus, a city’s leadership and staff can concentrate
their limited resources on matters that may be more pressing. Second, PG&E is regulated by the
state via the California Public Utilities Commission (CPUC), which oversees its power
procurement and approves its rates. While CCEs are partially regulated by the CPUC (e.g.,
ensuring that the CCE complies with any applicable laws), they are not subject to rate regulation.
Some may see state oversight as a benefit, with an official “watchdog” overseeing power supply
and procurement, while others might see the local CCE board accountability as a benefit. Third,
PG&E is much larger than any of the CCE options that Contra Costa Communities might pursue,
which (as discussed) might reduce community input and value but also provides some economies
of scale. For example, one poor power contract entered might have significant rate or operational
ramifications for a CCE. For PG&E, given its size, the impact of that same poor contract would
be diluted. Lastly, simply because a Contra Costa community does not join a CCE in 2017 or
2018 does not necessarily preclude it from doing so in the future, although waiting may result in
an “entry fee” or perhaps a high PCIA rate.
Summary
The following lays out the principal benefits and risks of each of the options considered.
Potential Benefits of Forming Contra Costa CCE (relative to joining MCE or EBCE)
More local control (voting shares not diluted)
Can form JPA and policies to fully reflect County interests and values
Greatest potential for local economic development (due largely to more local control)
Even if formed, individuals may still select PG&E as their power provider
Potential Risks/Downsides of Forming Contra Costa CCE (relative to joining MCE or
EBCE)
Commitment of County and city resources to establish a new CCE agency
Higher risks due lack of experience, fewer partners
Would need to establish programs, contractors, credit, etc.
Longest time line to begin enrolling customers
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Potential Benefits of joining MCE (relative to joining EBCE)
5 other Contra Costa County communities have already joined
Established, successful program with credit capacity and programs in place
Likely easier transition/implementation
Likely will be able to enroll customers sooner than EBCE
Potential Risks/Downsides of joining MCE (relative to joining EBCE)
May have less Board representation (if all of Contra Costa County and its jurisdictions
are represented by a shared seat)
May be less of a “fit” compared to East Bay identification and sensibilities (or, for some
cities, this may be a benefit)
Programs are already in place; less/minimal input into their formation
joining a large Board serving a very diverse customer base and geography
Potential Benefits of joining EBCE (relative to joining MCE)
Coming in closer to the “ground floor" — opportunity to influence policy direction and
program development
May be more mission or cultural alignment (East Bay vs. Marin) (or perhaps for some
communities, not)
Board will more likely be one seat per member jurisdiction (not a shared seat)
Weighted voting process is a little clearer
EBCE working on a local development business plan with emphasis on local power
production in the East Bay
Potential Risks/Downsides of joining EBCE (relative to joining MCE)
Likely to take longer to enroll County communities
Path to joining is not clear
May be a small fish among some very large fishes (Oakland, Hayward)
Union focused policies may be difficult for some
Potential Benefits of Remaining with PG&E (relative to joining or forming a CCE)
Experienced provider
State regulatory protection
Continuity- same firm provides all services
No action needed by City/County—status quo
May be able to join a CCE at a later date (but perhaps at some cost)
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Potential Risks/Downsides Benefits of Remaining with PG&E (relative to joining or
forming a CCE)
Higher GHG emissions
Less local renewable generation
Higher electricity rates than CCE rates under most scenarios
Less local control
Less local input into policies and offerings
Less local economic development
Individuals can remain on bundled PG&E service even though their community is a CCE
member.
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Chapter 8: Other Issues Investigated
Synergies on the Northern Waterfront
Contra Costa County has an ongoing initiative to economically develop its Northern Waterfront.
The Northern Waterfront stretches from the City of Hercules at San Pablo Bay, along the
southern shore of the Carquinez Straight and Suisun Bay, and out to the San Joaquin Delta
region of Oakley. The County’s Northern Waterfront Economic Development Initiative is a
regional cluster-based economic development strategy with a goal of creating 18,000 new jobs
by 2035. The Initiative leverages existing competitive advantages and assets by focusing on
advanced manufacturing sub-sectors in five targeted clusters (advanced transportation fuels, bio-
tech/bio medical, diverse manufacturing, food processing, and clean tech).
To assess the potential positive impacts a CCE might have on this Area, the study looked at the
Northern Waterfront to assess local generation potential within the area. Of the potential 3,350
MW of solar resources in the County, approximately 40% lies within the Northern Waterfront.
As shown in Table 31, there are over 700 potential solar sites in the Area, which could
theoretically generate over 2,000 GWhs. Of these sites, over 800 MW have the highest potential
ranking, meaning that they are the most appropriate for actual development. In fact, all the local
solar capacity specified in Scenarios 3 or 4 could be met at sites in the Northern Waterfront
alone.
Table 31 Solar Potential in the Northern Waterfront
Location Solar
Sites
PV Potential
(MW)
PV Production
(GWh)
Build Cost
($ Thousands)
Antioch 189 327 524 $747,130
Concord 108 191 306 $442,015
Crockett 21 58 93 $125,187
Hercules 52 90 144 $200,512
Martinez 139 300 480 $629,130
Oakley 43 76 121 $178,390
Pinole 17 24 39 $57,208
Pittsburg 153 298 477 $679,851
Rodeo 14 35 57 $85,875
Grand Total 736 1,400 2,241 $3,145,298
How much solar could actually be sited in the Northern Waterfront would depend upon (a) the
degree to which there is competition for sites for perhaps higher-value projects (b) the CCE’s
policies toward fostering local projects.
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In addition to this renewable potential, the Northern Waterfront also hosts six major power plants
(Table 32). In addition to these, the refineries in the area also generate much of their own power.
A Contra Costa CCE could contract with one of more of these facilities to provide the CCE’s
Resource Adequacy Requirements or a portion of its energy needs. Alone, a Contra Costa CCE
would not be able to use all—or even most—of the power produced by any of these or other
major power plant of this magnitude (e.g., the cancelled Oakley power plant).
Table 32. Natural Gas Power Plants in the Northern Waterfront
Plant Location Capacity
(MW)
Year in
Service Owner Type
Crockett Cogen Crocket 275 1995
Steam-Cogen
Los Medanos Pittsburg 555 2001 Calpine Combined cycle -Cogen
Delta Energy Facility Pittsburg 887 2002 Calpine Combined cycle
Gateway Antioch 530 2009 PG&E Combined cycle
March Landing Antioch 760 2013 Mirant combined cycle
Pittsburg Pittsburg 1,029 1970s NRG Steam, combined cycle
“Minimum” CCE Size?
MRW’s analysis above assumed that all eligible Contra Costa County cities join the Contra
Costa County CCE program with a participation rate of 85% from each city, resulting in an
anticipated CCE load of about 3.6 million MWh per year.59 If fewer customers join, CCE rates
will generally be higher because about $7 million of annual CCE costs are invariant to the
amount of CCE load. Along with the number of customers, the customer make-up is also
important. For example, a higher share of residential customers would improve the
competitiveness of the CCE, while a higher share of commercial customers or industrial
customers would weaken the competitiveness of the CCE. Since cities vary in their distribution
of customers by rate class, a city opting out of the CCE could affect the competitiveness of the
CCE due to both the reduction in CCE load and the shift in customer make-up.
To identify the “minimum” load needed for CCE customer rates to be no higher than PG&E
customer rates, we will analyze only the period between 2018 and 2030. The “minimum” load
for this period is approximately 440,000 MWh per year, assuming the average customer portfolio
for Contra Costa County and Supply Scenario 1. This value was estimated by assuming that the
fixed costs remained the same (i.e., did not scale with sales) and then lowering the sales until the
hypothetical reduced CCE’s rates were equal to PG&E’s. As shown in Figure 31, this is roughly
the load from the big cities (Concord and Pittsburg) and is much smaller than the load from the
unincorporated area. As long as two medium-sized cities or one larger city joins the CCE, this
“minimum” load will be met. It is not a true minimum, however, because the true minimum
depends on the make-up of the customer portfolio; for example, for the stand-alone city of
59 In the alternate supply scenarios, the “minimum” annual load assuming the average customer portfolio for Contra
Costa County and the base case is 550,000 MWh (Scenario 2).
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Pittsburg60, due to its load with more industrial proportion, the CCE program wouldn’t be cost-
competitive.
Figure 31. Potential load (85% participation) per city
Individuals and Communities Self-Selecting 100% Renewables
The existing CCEs all offer customers an option to choose to receive 100% of their power from
renewable resources in exchange for a rate premium. However, each CCE’s program is different.
MCE Clean Energy has offered its “Deep Green” at a rate premium of 1¢/kWh since its
inception. Sonoma Clean Power offers its “Evergreen” option at approximately the same price as
PG&E’s “Solar Choice” rate. Lancaster Choice Energy offers its Smart Choice as a fixed
monthly premium rather than a variable rate. In all cases, only a very modest number of CCE
customers—on the order of a few percent—have selected the 100% green rate option.
Table 33. CCE 100% Green Rate Premiums
CCE Rate Option Increment Above Default
Rate
Marin Clean Energy Deep Green 1¢/kWh
Sonoma Clean Power EverGreen 3.5¢/kWh
Lancaster Choice Energy Smart Choice $10/month
Peninsula Clean Energy ECO100 1¢/kWh
Potential Contra Costa Co. CCE TBD ~1.5¢/kWh
60 See Figure 2. Pittsburg is the only city with this highly industrial profile.
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Any full renewable pricing option offered by the Contra Costa County CCE would have to be set
by the CCE’s management. The value shown in Table 33, ~1.5¢/kWh, is the average incremental
cost of green power used in the CCE supply assessment (Scenario 2) over the study period.
(Initially, it would have to be ~1.9¢/kWh.) The number of customers selecting the rate would
not impact the economics of the CCE customer who remain on the standard rate.
Separate CCE opt-out notifications would be needed. A key feature of the opt-out
notification is the price comparisons against PG&E. As the default rate would be
different for these communities, a different notice would have to be sent. This
would simply increase the start-up cost for the CCE, the increment could be paid
for by the city electing a different default rate.
Having a higher default rate might increase the number of oft-outs in the
community.
PG&E’s billing system would have to be able to handle city- or zip code-specific
default options. That is, as new residential or businesses move to a self-selected
green community, the billing system would need to know to default them on a
different rate schedule than a customer in a different CCE community. This may
or may not be an issue.
Competition with a PG&E Solar Choice Program
PG&E has been offering a solar choice program known as Green Tariff Shared Renewable
Program since February 2015.61 The program was established under Senate Bill 43, and pursuant
to Decision 15-01-051 from the CPUC, to extend access to renewable energy to ratepayers that
are currently unable to install onsite generation.62 It offers homes and businesses the option to
purchase 50% or 100% of their energy use from solar resources. The program provides those
with homes or apartments or businesses that cannot support rooftop solar the opportunity to meet
their electricity requirements through renewable energy and support the growth of renewable
energy resources.
PG&E’s current Solar Choice program costs residential customers an additional 3.58¢/kWh.
Given that MRW projects that the CCE can offer 100% green power at ~1.5¢/kWh over its own
Scenario 1 or Scenario 2 rate (which is projected to be less than PG&E’s), we do not believe
PG&E’s Community Solar Program will be price competitive with similar CCE product options.
The program is open for enrollment until subscriptions reach 272 MW or January 1, 2019,
whichever comes first.63 While this does limit the ability for PG&E to provide a 100% renewable
61 PG&E website
http://www.pge.com/en/b2b/energysupply/wholesaleelectricsuppliersolicitation/RFO/CommunitySolarCho ice.page?
WT.mc_id=Vanity_communitysolarchoice . Accessed 5/16/2016
62 California Public Utilities Commission, Decision 15-01-051, p.3
63 Solar Choice Program FAQs website,
https://www.pge.com/en/myhome/saveenergymoney/solar/choice/faq/index.page Accessed, 5/16/2016
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option in the long-run, at the start of the CCE this program it provides an opportunity for
customers who desire 100% renewable power to remain with PG&E.
Differences Between the Analyses for Contra Costa and Alameda Counties
In the first half of 2016, MRW prepared a similar CCE analysis for Alameda County. 64
Although the fundamental approach and results of study and this one are the same, there are
several differing assumptions resulting in differing results. If we compare the results of the
present study with the results obtained in the Alameda CCE study, we observe that the savings
for CCE customers are very similar in both studies, though PG&E rates and CCE rates are both
approximately 1¢/kWh higher in the current study than in the prior study (Table 34).
Table 34. Average prices for 2018-2030 Scenario 1 for Contra Costa and Alameda County
CCE programs
Average Period 2018-2030 Contra Costa County Alameda County
Price natural gas ($/MMBtu) 5.70 4.90
Wholesale ($/MWh) 51.30 44.80
PG&E Capacity ($/MWh) 74 39
CCE Capacity ($/MWh) 52 39
Wind ($/MWh) 56 57
Solar Distant ($/MWh) 51 51
Solar Local ($/MWh) 70 74
% Local Solar by 2030 25% 10%
PG&E rate (¢/kWh) 11.7 10.4
PCIA rate (¢/kWh) 1.4 1.4
CCE rate (¢/kWh) 9.4 8.3
Difference CCE-PGE (¢/kWh) 2.3 2.1
The results of the present study for Contra Costa County differ from the prior results for
Alameda County because we updated our forecast to reflect new PG&E rate fillings and other
public forecasts. The main changes between the models are as follows:
Bundled Load Forecast: As a result of increased interest in CCE, PG&E’s most recent
bundled load forecasts are 3% below the previously available forecasts for 2017 and an
average of 25% below the previously available forecasts over the 2018-2030 period (see
64 The final version of the Alameda CCE technical study was published on July 1, 2016.
https://www.acgov.org/cda/planning/cca/documents/Feas -TechAnalysisDRAFT5312016.pdf
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Figure 32).65 Less load reduces PG&E’s procurement costs, increases the share of fixed costs
paid by remaining bundled customers, and increases the revenue provided to bundled
customers from CCE exit fees. These effects mostly offset each other, resulting in little net
change to bundled rates.66
Natural gas prices: Projections for natural gas prices are about $0.80/MMBtu higher than
they were in the spring when the Alameda County report was developed. The higher natural
gas prices increase wholesale market prices by $7/MWh (14%).
Diablo Canyon Retirement application: In July 2016, PG&E, together with other entities,
submitted a proposal to retire the two units of Diablo Canyon when their licenses expire in
November 2024 and August 2025. Per the proposal, PG&E would replace Diablo Canyon
production with energy efficiency and greenhouse gas-free generation resources. These
resources would include the following: (1) 2,000 GWh of load reduction from additional
energy efficiency to be installed by January 2025, (2) 2,000 GWh of load reduction or
generation from GHG-free generation resources to be on-line between 2025 and 2030, and
(3) a voluntary commitment from PG&E to meet a 55% RPS for 2031-2045 (instead of the
65 The sources for the 2017 bundled load forecasts are PG&E’s 2017 preliminary and final ERRA forecasts. (The
June 2016 preliminary forecast was used in the Alameda County CCE study, and the November 2016 final forecast
was used in the present study.) The sources for the 2018-2030 bundled load forecasts are PG&E’s RPS plans for
2015 (filed in January 2016, used for Alameda County) and for 2016 (draft filed in August 2016, used for Contra
Costa).
66 CCE exit fees are designed so that bundled customers’ rates are not affected by CCE departures. In practice,
some impact is likely in one direction or the other, and the magnitude and direction of this impact may each vary
year by year.
Figure 32: Bundled Load Forecasts used in the Alameda and Contra
Costa County Analyses
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50% requirement currently in effect). The joint proposal estimated that the retirement of
Diablo Canyon would result in a need for new generation capacity (“load-resource balance”)
around 2030, which is about five years earlier than previously anticipated.
The new energy efficiency resources together with other costs of the nuclear plant retirement
would be recovered through non-generation rates (mostly Public Purpose Program and
Nuclear Decommissioning charges), and the new RPS resources would be recovered through
a new “Clean Energy Charge” applied to all PG&E retail customers. For those load serving
entities that are willing to commit to procuring the equivalent new RPS resources, PG&E has
proposed a “self-provision” option that would exempt existing DA and CCE loads from the
Clean Energy Charge. In the analysis for Contra Costa County, MRW assumed that Contra
Costa CCE would choose the “self-provision” option.
MRW assumed for this study that the Diablo Canyon retirement proposal would be adopted,
though the proposal is under evaluation by the Commission and is subject to modification.
Based on this proposal, we modified the PG&E and Contra Costa County CCE power supply
forecasts as follows:67
1) PG&E’s RPS requirements were increased for 2030-2038 from 50% to 55%,68
2) Contra Costa County CCE’s RPS requirements were increased for 2030-2038 to 55%
(vs. the 50% that was used in the Alameda County CCE study), and
3) We began increasing the price of capacity five years earlier than we had in the
Alameda County CCE study, reflecting the earlier load-resource balance date due to
the retirement of Diablo Canyon. For both Alameda and Contra Costa counties,
MRW assumed that the CCEs would build their own power plants (alone or in
combination with other public entities) in place of purchasing market capacity when
market prices rise above the cost of a new self-build.
67 We also accounted for the changes in the Public Purpose Program and Nuclear Decommissioning fees in our
calculation of the Residential bills.
68 The generation share of the 2025-2030 commitment for 2,000 GWh of load reduction or GHG -free generation
was assumed to be subsumed by procurement needed to meet a 50% RPS by 20 30 and therefore did not result in
incremental renewable generation in our model.
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Chapter 9: Conclusions
Overall, a CCE in Contra Costa County appears feasible. Given current and expected market and
regulatory conditions, a Contra Costa County CCE should be able to offer its residents and
business electric rates that are less than that available from PG&E.
Sensitivity analyses suggest that these results are relatively robust. Only when very high
amounts of renewable energy are assumed in the CCE portfolio (Scenario 3), combined with
other negative factors, do PG&E’s rates become consistently more favorable than the CCEs.
A Contra Costa County CCE would also be well positioned to help facilitate greater amounts
renewable generation to be installed in the County. Because the CCE would have a much greater
interest in developing local solar than PG&E, it is much more likely that such development
would actually occur with a CCE in the County than without it.
The CCE can also reduce the amount greenhouse gases emitted by the County, but only under
certain circumstances. Because PG&E’s supply portfolio has significant carbon-free generation
(large hydroelectric and nuclear generators), the CCE must contract for significant amounts of
carbon-fee power above and beyond the required qualifying renewables in order to actually
reduce the County’s electric carbon footprint. Therefore, if carbon reductions are a high priority
for the CCE, a concerted effort to contract with hydroelectric or other carbon-free generators
would be needed.
A CCE can also offer positive economic development and employment benefits to the County.
At the peak, the CCE could create approximately 500 to 1000 new jobs in the County, plus an
additional 200 jobs in the neighboring counties if local renewable development is prioritized.
While the analytical focus of this report has been on a stand-alone Contra Costa County CCE,
that is not the only, nor necessarily best, choice for Contra Costa Communities. Overall, there is
insufficient data to suggest that a stand-alone Contra Costa CCE would offer lower rates or
greater GHG savings that joining MCE or EBCE. Either forming or joining a CCE would likely
offer modestly lower rates and more local economic development that remaining with PG&E.
Joining MCE would likely result in the quickest path to CCE implementation, however at a loss
of local control and CCE policy formation. Because it has yet to be formed, joining with EBCE
would take longer than joining the already-established MCE, but would offer greater input into
the CCE’s policies and formation.
Although this study suggests CCE program options would likely produce both environmental
and economic benefits for the jurisdictions included in the study, continuing service with PG&E
remains an option for not only a community but also for any individual or business whose
community has selected CCE service. PG&E is an experienced power provider, and is regulated
by the state. Furthermore, remaining with PG&E takes no city action. Lastly, simply because a
Contra Costa community does not join a CCE in 2017 or 2018 does not necessarily preclude it
from doing so in the future, although waiting may result in an “entry fee” or perhaps a high
PCIA rate.
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DRAFT FOR REVIEW
Technical Study for Community Choice Aggregation
Program in Costa County
Appendices
Prepared by:
With
MRW & Associates, LLC
1814 Franklin Street, Ste 720
Oakland, CA 94612
Economic
Development
Research Group
Boston, MA
Sage Renewables
San Francisco, CA
November 30, 2016
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Appendix A. Loads and Forecast
Appendix B. Power Supply Cost
Appendix C. Forecast of PG&E’s Generation Rates
Appendix D. Detailed Pro Forma and CCA Rates
Appendix E. Greenhouse Gas Emissions and Costs
Appendix F. Macroeconomic Analysis
Appendix G. Proforma
Appendix H. MCE and EBCE’s Joint Power Agreements
Appendix I. MCE’s approval for inclusion of Contra Costa
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Appendix A. Loads and Forecast
2014 Load (MWh) Residential Commercial Industrial Public Street lights +
Pumping
UNINCORPORATED 454,716 252,156 237,085 63,574 19,925
CONCORD 269,024 242,584 53,969 18,228 885
PITTSBURG 145,304 134,197 225,362 14,807 1,635
ANTIOCH 270,761 109,487 18,340 18,694 1,077
SAN RAMON 172,364 140,696 32,012 14,458 4,461
BRENTWOOD 150,827 66,635 0 16,407 4,970
DANVILLE 133,085 51,478 0 11,944 1,394
MARTINEZ 86,638 61,730 6,372 6,121 1,140
PLEASANT HILL 82,411 67,087 0 5,905 1,270
OAKLEY 96,389 18,236 0 12,431 901
ORINDA 58,779 14,719 0 39,747 215
HERCULES 48,162 32,749 0 2,751 700
PINOLE 36,629 26,028 0 5,877 963
MORAGA 40,593 8,818 0 3,701 456
CLAYTON 31,795 4,759 0 1,808 661
TOTAL 2,077,476 1,231,360 573,139 236,454 40,652
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Appendix B. Power Supply Cost
MRW has developed a bottoms-up calculation of Costa County CCA’s power supply costs,
separately forecasting the cost of each power supply element. These elements are renewable
energy, non-renewable energy (including power production costs and greenhouse gas costs),
resource adequacy (RA) capacity (both renewable and non-renewable supplies) and related costs
(e.g., CAISO expenses and broker fees).1 Figure 1 illustrates the components of Costa County
CCA’s expected supply costs.
Figure 1: Power Supply Cost Forecast
Renewable Power Cost Forecast
MRW developed a forecast of renewable generation prices starting from an assessment of the
current market price for renewable power. For the current market price, MRW relied on wind
and solar contract prices reported by California municipal utilities and Community Choice
Aggregation (CCA) entities in 2015 and early 2016, finding an average price of $52 per MWh
for these contracts.2
1 MRW included a 5.5% adder in the power supply cost for CAISO costs (ancillary services, etc.), and a 5%
premium for contracted supplies to reflect broker fees and similar expenses.
2 MRW relied exclusively on prices from municipal utilities and CCAs because investor-owned utility contract
prices from this period are not yet public. We included all reported wind and solar power purchase agreements,
excluding local builds (which generally come at a price premium), as reported in California Energy Markets, an
Power Supply
Costs
Renewable
Power
Energy and
Capacity
Over-
generation
Non-
Renewable
Power
Energy
Power
Production
Greenhouse
Gas
Capacity
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To forecast the future price of renewable purchases, MRW considered a number of factors:
Researchers from the National Renewable Energy Laboratory (NREL) and Lawrence
Berkeley National Laboratory (LBNL) developed a set of forecasts of utility-scale solar
costs based on market data and preliminary data from other research efforts.3 Their base
case forecast predicts a 3.8% annual decline in utility-scale solar capital costs on a
nominal basis, from $1,932/kW-DC in 2016 to $1,652/kW-DC in 2020, with costs then
remaining roughly constant in nominal dollars through 2030.4 Additional scenarios
predict even steeper price declines, with the most aggressive scenario predicting an 11%
annual nominal decline through 2020, with increases at the rate of inflation after that.
The federal Investment Tax Credit (ITC), which is commonly used by solar developers,
is scheduled to remain at its current level of 30% through 2019 and then to fall over three
years to 10%, where it is to remain.5 The federal Production Tax Credit, which is
commonly used by wind developers, is scheduled to be reduced for facilities
commencing construction in 2017-2019 and eliminated for subsequent construction.6 The
loss of these credits would put upward pressure on prices.
NREL and LBNL researchers predicted in 2015 that the cost increase associated with an
ITC reduction would be roughly offset by other solar cost reductions even if the full
reduction to 10% were to be implemented by 2018, rather than spread out through 2022
as is currently planned.7
Lawrence Berkeley National Laboratory researchers conducted a study anticipating a
reduction of the wind costs of 24% by 2030 and 35% by 2050.8
independent news service from Energy Newsdata, from January 2015-January 2016 (see issues dated July 31,
August 14, October 16, October 30, 2015, and January 15, 2016).
3 National Renewable Energy Laboratory. Impact of Federal Tax Policy on Utility-Scale Solar Deployment Given
Financing Interactions, September 28, 2015, Slide 16. http://www.nrel.gov/docs/fy16osti/65014.pdf
4 Ibid. Costs converted to nominal dollars using the inflation forecast used throughout the rate forecast model (U.S.
EIA’s forecast of the Gross Domestic Product Implicit Price Deflator).
5 U.S. Department of Energy. Business Energy Investment Tax Credit (ITC). http://energy.gov/savings/business-
energy-investment-tax-credit-itc
6 U.S. Department of Energy. Electricity Production Tax Credit (PTC). http://energy.gov/savings/renewable-
electricity-production-tax-credit-ptc
7 National Renewable Energy Laboratory. Impact of Federal Tax Policy on Utility-Scale Solar Deployment Given
Financing Interactions, September 28, 2015, Slide 28.
8 Lawrence Berkeley National Laboratory . Expert elicitation survey on future wind and energy costs. Nature
Energy, September 12th, 2016.
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The production tax credit has been extended six times from 2000-2014,9 and the solar
ITC has been extended three times since 2007.10 Further tax credit extensions are
therefore plausible.
The major California investor-owned utilities have significantly slowed their renewable
procurement because lower-than-expected customer sales and higher-than-expected
contracting success rates have led to procurement in excess of the RPS requirements
through 2020. When the utilities start ramping their procurement back up to meet the
50%-by-2030 RPS requirement, the supply-demand balance in the market may shift,
resulting in higher-than-expected prices unless an increase in suppliers and development
opportunities matches the increase in demand.
Given the potential upward price pressures from tax credits that are currently expected to expire
and from higher demand for renewable power to meet the 50%-by-2030 requirement and the
potential downward price pressures from falling renewable development costs, the possibility for
lower cost procurement through the use of RECs, and the possibility that the expiry of the tax
credits will be further delayed, it is unclear whether renewable prices will continue to fall (as
NREL, LBNL, and others are predicting) or will start to stabilize and rise.
MRW has addressed this uncertainty by considering two scenarios for this sensitivity case:
In the solar base renewable cost forecast, MRW used the $48.5 per MWh average price
of recent municipal utility and CCA solar contracts as the price through 2022 (in
nominal dollars), which will increase with inflation in subsequent years. This results in a
solar price of $57 per MWh in 2030, and of $67 per MWh in 2038. In the wind base
renewable cost forecast, MRW used the $55.0 per MWh average price of recent
municipal utility and CCA solar contracts as starting point, and extended it applying an
annual decrease of 2% through 2030 and 1% through 2038, offset by inflation. This
results in a wind price of $57 per MWh in 2030, and of $62 per MWh in 2038.
In the high renewable cost scenario, MRW increased both wind and solar base case
prices to account for the expected expiration of the tax credits, resulting in average a
price of $75 per MWh in 2030 and $86 per MWh in 2038. These scenarios provide a
reasonable window of renewable price projections based on current market conditions
and analysts’ expectations.
MRW used these same renewable prices to calculate PG&E’s renewable power costs. However,
as described in Appendix B in the PG&E forecast, these renewable energy prices are used only
9 Union of Concerned Scientists. Production Tax Credit for Renewable Energy.
http://www.ucsusa.org/clean_energy/smart-energy-solutions/increase-renewables/production-tax-credit-for.html
10 Solar Energy Industries Association. Solar Investment Tax Credit. http://www.seia.org/policy/finance-tax/solar-
investment-tax-credit; and U.S. Department of Energy. Business Energy Investment Tax Credit (ITC).
http://energy.gov/savings/business-energy-investment-tax-credit-itc
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for incremental power that is needed above PG&E’s existing RPS contracts. For Costa County
CCA, these prices are used as the basis for its entire RPS-eligible portfolio.
MRW additionally included a premium for the portion of Costa County CCA’s RPS portfolio
assumed in each scenario to be located in Costa County County. While solar energy is
anticipated to provide the largest share of incremental supply located in-county, the solar
resource in Costa County is not as strong as in the areas being developed to supply the contracts
discussed above. As a result, the cost of solar generation in Costa County is expected to be
higher than the assumed contract prices for non-Costa County supplies. Based on information
provided in the CPUC’s current RPS calculator, combined with SAGE inputs (performance
assumptions and capital cost of the projects11), the current cost for solar generation in Costa
County is expected to be approximately $68 per MWh. In addition, it is assumed the local solar
generation cost will scale with installed capacity, resulting in a local solar generation cost of $82
per MWh for 1000 MW of installed capacity.
Non-Renewable Energy Cost Forecast
MRW separated the costs of non-renewable energy generation into two components: power
production costs and greenhouse gas costs. The forecast methodologies for these cost elements,
described below, are consistent with the forecast methodologies used for these cost elements in
the PG&E rate forecast.
Since natural gas generation is typically on the margin in the California wholesale power market,
power production costs for market power are driven by the price for natural gas. MRW
forecasted natural gas prices based on current NYMEX market futures prices for natural gas,
projected long-term natural gas prices in the EIA’s 2016 Annual Energy Outlook,12 and PG&E’s
tariffed natural gas transportation rates.13 MRW used a standard methodology of multiplying the
natural gas price by the expected heat rate for a gas-fired unit and adding in variable operations
and maintenance costs to calculate total power production costs.
In addition to power production costs, the cost of energy generated in or delivered to California
also includes the cost of greenhouse gas allowances that, per the state’s cap-and-trade program,
must be procured to cover the greenhouse gases emitted by the energy generation. MRW
estimated the price of GHG allowances to equal the auction floor price stipulated by the ARB’s
cap-and-trade regulation, consistent with recent auction outcomes.14 MRW estimated the
11 Capital cost for local solar projects in Contra Costa County, according to SAGE price curve, is $1,350 per kW
installed for the first 400MW solar installed in the county. MRW calculated the average price for the cumulative
developed capacity forecast for each year (counting only 50% of the capacity of each developed project towards the
cumulative total).
12 U.S. Energy Information Administration. “2016 Annual Energy Outlook,” Table 13.
13 Pacific Gas & Electric, Burnertip Transporation Charges. Tariff G-EG, Advice Letter 3664-G, January 2016 and
Tariff G-SUR, Advice Letter 3699-G, April 2016.
14 California Code of Regulations, Title 17, Article 5, Section 95911.
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emissions rate of Costa County CCA non-renewable power supply based on an estimated heat
rate for market power multiplied by the emissions factor for natural gas combustion.15
Capacity Cost Forecast for Non-Renewable Power
To estimate Costa County CCA’s capacity requirements, MRW developed a forecast of Costa
County CCA’s peak demand in each year and subtracted the net qualifying capacity credits
provided by Costa County CCA’s renewable power purchases. This is appropriate because the
renewable energy prices used in this analysis reflect prices for contracts that supply both energy
and capacity. If Costa County CCA purchases renewable energy via energy-only contracts, Costa
County CCA’s need for capacity will be greater than forecasted here, but these higher costs will
be fully offset by the lower costs for the renewable energy.
MRW estimated current peak demand for Costa County CCA’s load using the 2015 monthly
bills for all the current PG&E clients in Costa County county16 and PG&E’s class-average load
profiles. We forecasted changes to this peak demand based on the Contra Costa load forecast.17
We calculated capacity requirements as 115% of the expected peak demand in order to include
sufficient capacity to fulfill resource adequacy requirements. We applied a consistent
methodology to obtain the peak demand growth rates and capacity requirements for PG&E.
To estimate the cost of Costa County CCA’s capacity needs, MRW priced capacity purchases at
the median price of recent Resource Adequacy purchases, escalated with inflation.18
To estimate the cost of Costa County CCA’s capacity needs, MRW considered two time periods:
the period before system load-resource balance when there is excess capacity on the system, and
the period following system-load resource balance when additional supply must be developed.
MRW assumed a system load-resource balance year of 2030.19 Through 2025, MRW priced
capacity at the median price of recent resource adequacy purchases, escalated with inflation.
MRW increased the capacity price incrementally starting in 2026 to reflect an increase in the
market price for capacity during the transition from the lower near-term prices to the higher post-
load-resource balance prices. MRW assumed that Costa County CCA would build its own power
plant (alone or in combination with other public entities) in place of purchasing market capacity
when market prices rise above the cost of a new self-build. In MRW’s model, this occurs in
15 U.S. EIA. Electric Power Annual (EPA), February 16, 2016, Table A.3.
https://www.eia.gov/electricity/annual/html/epa_a_03.html
16 Monthly bills corresponding to 2015 for all the clients in Contra Costa County provided by PG&E.
17 California Energy Commission. Demand Forecast. PG&E Forecast Zone Results Mid Demand Case, Sales
Forecast, Central Valley Region. December 14, 2015.
18 CPUC 2013-2014 Resource Adequacy Report Final, August 5, 2015, page 23 Table 11.
19 According to the assumption adopted by the CPUC in December 2015 for long-term forecasting purposes, the
load resource balance year was 2035. MRW opted to advance this to 2030 due to the retirement of the Diablo
Canyon nuclear facility.
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2030. From this point on, MRW assumed that the market price for Costa County CCA’s capacity
would be equal to the levelized fixed cost of a new advanced combustion turbine developed by a
publicly owned utility, minus levelized gross margins from energy sales. A similar methodology
was used to forecast the cost of capacity for PG&E; however, PG&E’s post-load-resource
balance price forecast is based on the price of a combustion turbine developed by a merchant
developer (see Appendix C).
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Appendix C. Forecast of PG&E’s Generation Rates
MRW developed a forecast of PG&E’s generation rates for comparison with the rates that Costa
County CCA will need to charge to cover its costs of service. MRW developed the forecast for
the years 2018-2038 using publicly available inputs, including cost and procurement data from
PG&E, market price data, and data from California state regulatory agencies and the U.S. Energy
Information Administration. The structure of the rate forecast model and the basic assumptions
and inputs used are described below.
Generation Charges
PG&E’s generation costs fall into four broad categories: (1) renewable generation costs, (2) fixed
costs of non-renewable utility-owned generation, (3) fuel and purchased power costs for non-
renewable generation, and (4) capacity costs. Each of these categories is evaluated separately in
the rate forecast model, and underlying these forecasts is a forecast of PG&E’s generation sales.
Sales Forecast
PG&E’s generation cost forecast is driven in large part by the amount of generation that PG&E
will need to obtain to meet customer demand. To forecast PG&E’s electricity sales, MRW
started with the 2016-2030 sales forecast that PG&E provided in its August 2016 Renewable
Energy Procurement Plan (“RPS Plan”) filing with the CPUC.20 This forecast predicts an 8%
annual sales reduction through 2020, a 2% reduction per year from 2021-2028, and a rather
anemic sales growth of 0.2% per year from 2029-2030.21 MRW extended the sales forecast
through 2038, maintaining this 0.2% increase per year.
Renewable Generation
The starting point for MRW’s analysis is PG&E’s “RPS Plan,” in which PG&E discusses its plan
for meeting California’s Renewable Portfolio Standard (RPS) targets and provides the annual
amount and cost of renewable generation currently under contract through 2030. PG&E’s RPS
Plan shows that PG&E’s current renewable procurement is in excess of the RPS requirement in
each year through 2026. After 2022, PG&E’s renewable generation from current contracts falls
below the RPS requirements, but PG&E is projected to have enough banked Renewable Energy
Credits (RECs) from excess renewable procurement in prior years to meet the RPS requirements
until 2034.
20 Pacific Gas & Electric. Renewables Portfolio Standard 2016 Renewable Energy Procurement Plan (Draft
Version). August 8, 2016. Appendix D.
21 The near-term decline in sales in PG&E’s forecast is likely attributable to the growth in CCA, in which a
municipality procures electric power on behalf of its constituents instead of having them purchase their power from
PG&E. While customers in the jurisdictions of these municipalities have the option to opt-out of CCA and to
continue to procure power from PG&E, so far, most CCA-eligible customers have not elected for this option. CCA
customers continue to procure electricity delivery services from PG&E; it is only generation services that they
obtain through the CCA.
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MRW adopted PG&E’s RPS Plan forecast of the amount and cost of renewable generation that is
currently under contract. For the period starting in 2034 when PG&E’s RPS Plan shows a need
for incremental renewable procurement to meet RPS requirements, MRW added in the necessary
renewable generation to meet current statutory requirements (i.e., 33% of procurement in 2020,
increasing to 50% of procurement in 2030, and to 55% of procurement in 2031).22 To project
PG&E’s cost of this incremental renewable generation, MRW used the same renewable prices
used for Costa County CCA’s renewable power cost forecast (see Appendix B).
Fixed Cost of Non-Renewable Utility-Owned Generation
PG&E’s rates include payment for the fixed costs of the PG&E-owned non-renewable generation
facilities, which are primarily natural gas, nuclear, and hydroelectric power plants. Because these
costs are not tied to the volume of electricity that PG&E sells, their annual escalation is not
driven by the price of fuel and other variable inputs. Instead, they escalate at a rate that stems
from a combination of cost increases and depreciation reductions. These escalation rates are
determined in General Rate Case (GRC) proceedings, which occur roughly every three years.
As a starting point for the forecast, MRW used the proposed 2017 fixed costs for these
facilities.23 For the period between 2018 and 2020, MRW increased the fixed cost based on
PG&E’s 2017 GRC settlements.24 For subsequent years, MRW estimated in the base case that
PG&E’s generation fixed costs would increase by the 6.2% annual average growth rate approved
and implemented for these cost over the last ten years.25 These escalation rates are in nominal
dollars (i.e., some of the escalation is accounted for by inflation).
22 MRW additionally allowed for the purchase of additional renewable generation when renewable prices are below
market prices, subject to some purchase limits, including a 50% cap on renewable generation relative to the entire
generation portfolio. This leads to additional renewable purchases from 2027-2029 in the Low Renewable Price
scenario. Starting in 2030, the RPS requirement is 50%, and no additional renewable purchases are allowed, per the
rules of the model, in order to maintain grid reliability.
23 Pacific Gas & Electric. Annual Electric True-Ups for 2017. Advice Letter 4902 E-A. September 13, 2016. Table 2
and Pacific Gas & Electric 2017 GRC Settlements, A.15-09-001, Appendix A and B.
24 Pacific Gas & Electric 2017 GRC Settlements, A.15-09-001, Appendix A and B
25 Historic growth rates calculated from Pacific Gas & Electric Advice Letters 2706-E-A, AL 3773-E, 4459-E, 4647-
E, and 4755-E. New power plant costs were excluded from these calculations since costs of new plants are offset, at
least in part, by a reduction in fuel and purchased power costs.
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Table 1: PG&E’s Generation Fixed Costs, 2011-201626
(Nominal $ Million) 2011 2012 2013 2014 2015 2016
Generation Fixed Costs 1,400 1,530 1,550 1,710 1,860 1,840
Annual Cost Increase 9% 1% 10% 9% -1%
MRW made adjustments to this GRC forecast to account for the retirement of the Diablo Canyon
nuclear units at the end of the units’ current licenses in 2024 and 2025.
Fuel and Purchased Power Costs for Non-Renewable Generation
Each spring, PG&E files a forecast with the CPUC of its fuel and purchased power costs for the
upcoming year in its “ERRA” filing, which PG&E updates and finalizes in November. MRW
relied on PG&E’s November 2017 ERRA testimony,27 adjusted to remove renewable generation
costs, as the starting point for the forecast of fuel and purchased power costs for PG&E’s non-
renewable generation.
To escalate these costs through the forecast period, MRW forecasted changes to natural gas
prices and greenhouse gas cap-and-trade program compliance costs, which are the major drivers
of change to these costs. The natural gas price forecast is based on current NYMEX market
futures prices for natural gas, forecasted natural gas prices in the U.S. EIA’s 2016 Annual Energy
Outlook, and PG&E’s tariffed natural gas transportation rates. This forecast is the same forecast
used in the forecast of Costa County CCA’s wholesale power costs (see Appendix B).
Cap-and-trade program compliance costs are estimated based on (1) PG&E’s forecast of carbon
dioxide emissions in 2017;28 (2) a forecast of PG&E’s fossil generation supply, developed by
subtracting expected renewable, hydroelectric, and nuclear generation from PG&E’s projected
wholesale power requirement; and (3) a forecast of greenhouse gas allowance prices. The
greenhouse gas allowance price forecast is the same as used in the forecast of Costa County CCA
wholesale power costs and is based on the auction floor price stipulated by the ARB’s cap-and-
trade regulation (see Appendix B).
26 2011-2013: CPUC Decision 11-05-018, pages 2 and 15; and 2014-2016: CPUC Decision 14-08-032,
Appendix C, Table 1 and Appendix D, Table 1.
27 PG&E Update To Prepared 2017 Energy Resource Recovery Account and Generation Non-Bypassable Charges
Forecast and Greenhouse Gas Forecast Revenue and Reconciliation, filed with the CPUC in proceeding A.1 6-06-
003 on Nov 2, 2016, Table 11-3.
28 PG&E Update To Prepared 2017 Energy Resource Recovery Account and Generation Non-Bypassable Charges
Forecast and Greenhouse Gas Forecast Revenue and Reconciliation, filed with the CPUC in proceeding A.1 6-06-
003 on Nov 2, 2016, Table 12-2.
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The MRW rate model calculates total fuel and purchased power costs by escalating natural gas
prices based on the natural gas price forecast described above, escalating nuclear fuel prices
based on the EIA forecast of fuel costs for nuclear plants, escalating water costs for hydroelectric
projects and the capacity costs of power purchase contracts with inflation, and pricing market
power at the same market power price used for Costa County CCA’s purchases. The model then
sums the cost for each of these resources and adds in projected cap-and-trade compliance costs to
this total cost.
Capacity Costs
PG&E must procure capacity to meet 115% of its anticipated peak demand in order to fulfill its
resource adequacy requirement. PG&E’s own power plants can be used to meet this requirement,
as can power plants with which PG&E has contracts.
To estimate PG&E’s capacity requirements, MRW started with the Capacity Supply Plan that
PG&E submitted to the California Energy Commission in 2015,29 which forecasts PG&E’s peak
demand and existing capacity resources for each of the years 2013-2024. With limited
exception,30 MRW used PG&E’s data where publicly available and extended the forecasts to
2038. In extending these forecasts, we used assumptions that are consistent with those used in
our assessments of energy sales and costs, including load growth escalation and the projected
retirement of PG&E’s nuclear plant. We also added in anticipated capacity from new renewable
procurement and from new energy storage and adjusted the calculation to account for the portion
of Resource Adequacy credits that is allocated to non-bundled customers.
As with the Costa County CCA’s capacity cost forecast, MRW priced capacity at the median
price of recent Resource Adequacy capacity sales, escalated with inflation.31
Rate Development
Following the methodologies described above, MRW developed a forecast of PG&E’s
generation revenue requirement and divided these expenses by the expected PG&E sales in order
to obtain a forecast of the system-average generation rate. We calculated annual escalators based
on these system-average rates and applied them to the generation rates that are currently in effect
for each customer class.32
29 California Energy Commission, Energy Almanac, Utility Capacity Supply Plans from 2015. September 4, 2015
30 The two main exceptions are that 1) MRW increased energy efficiency and demand response growth to comply
with SB 350 requirements to double energy efficiency by 2030 and the anticipated continuation of CPUC demand
response initiatives, and 2) MRW accounted for the energy efficiency and renewable capacity expected to be
installed because of the Diablo Canyon retirement application.
31 CPUC 2013-2014 Resource Adequacy Report Final, August 5, 2015, page 23 Table 11.
32 PG&E Advice Letter AL-4805-E, effective March 24, 2016.
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Appendix D. Detailed Pro Forma and CCA Rates
Case-Legend
Base BASE
Low participation LP
High price local LOC
High renewable prices RPS
High natural gas price GAS
Low PG&E portfolio costs LPGE
High PCIA PCIA
Stress Scenario STRS
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Scenario Sensitivity
Case
Rates
(¢/kWh) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 1 BASE CCA gen 7.0 7.1 7.1 7.4 7.6 7.8 7.9 8.0 8.4 8.8 9.3 9.9 10.5 10.8 11.1 11.4 11.7 12.0 12.4 12.7 13.1
1 BASE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
1 BASE CCA Res Fund 0.8 0.7 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 BASE PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
1 LP CCA gen 7.1 7.2 7.2 7.5 7.7 7.9 8.0 8.1 8.5 8.9 9.4 9.9 10.5 10.8 11.1 11.4 11.8 12.1 12.4 12.8 13.2
1 LP Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
1 LP CCA Res Fund 0.6 0.8 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 LP PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
1 LOC CCA gen 7.0 7.1 7.1 7.4 7.6 7.8 7.9 8.0 8.4 8.8 9.3 9.9 10.5 10.8 11.1 11.4 11.7 12.0 12.4 12.7 13.1
1 LOC Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
1 LOC CCA Res Fund 0.8 0.7 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 LOC PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
1 RPS CCA gen 7.1 7.2 7.3 7.8 8.1 8.5 8.6 8.8 9.2 9.7 10.2 10.8 11.4 11.8 12.2 12.5 12.9 13.2 13.6 14.0 14.4
1 RPS Exit fees 2.4 1.9 2.3 1.6 1.6 1.5 1.3 1.1 0.9 0.7 0.6 0.5 0.5 0.4 0.3 0.1 0.0 0.0 0.0 0.0 0.0
1 RPS CCA Res Fund 0.7 0.7 0.4 0.1 0.0 0.1 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 RPS PG&E gen 10.1 10.6 10.7 11.3 11.6 11.5 11.4 11.1 11.5 12.2 12.9 13.8 14.9 15.7 16.5 17.3 17.3 17.8 18.4 18.7 19.4
1 GAS CCA gen 8.1 8.5 8.8 9.2 9.5 9.4 9.4 9.6 10.0 10.4 10.8 11.3 11.9 12.3 12.6 12.9 13.3 13.7 14.2 14.6 15.0
1 GAS Exit fees 2.2 2.6 2.7 2.8 2.6 3.4 2.4 1.7 0.8 0.7 0.7 0.6 0.5 0.3 0.2 0.1 0.1 0.1 0.1 0.1 0.1
1 GAS CCA Res Fund 0.2 -0.1 0.0 0.0 0.0 0.0 0.0 1.4 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 GAS PG&E gen 10.5 10.9 11.0 11.4 11.9 11.0 11.3 11.8 12.3 12.9 13.5 14.3 15.3 15.4 15.8 16.2 16.7 17.1 17.7 18.3 19.0
1 LPGE CCA gen 7.0 7.1 7.1 7.4 7.6 7.8 7.9 8.0 8.4 8.8 9.3 9.9 10.5 10.8 11.1 11.4 11.7 12.0 12.4 12.7 13.1
1 LPGE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
1 LPGE CCA Res Fund 0.0 1.1 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 LPGE PG&E gen 9.1 9.5 9.6 10.1 10.4 10.2 10.2 9.8 10.2 10.7 11.4 12.1 13.0 13.2 13.6 14.0 14.5 14.9 15.3 15.8 16.4
1 PCIA CCA gen 7.0 7.1 7.1 7.4 7.6 7.8 7.9 8.0 8.4 8.8 9.3 9.9 10.5 10.8 11.1 11.4 11.7 12.0 12.4 12.7 13.1
1 PCIA Exit fees 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4
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1 PCIA CCA Res Fund 0.8 0.7 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
1 PCIA PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
1 STRS CCA gen 8.2 8.7 9.1 9.6 9.9 10.1 10.2 10.3 10.8 11.2 11.7 12.3 12.9 13.3 13.7 14.1 14.6 15.0 15.4 15.9 16.4
1 STRS Exit fees 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
1 STRS CCA Res Fund 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
1 STRS PG&E gen 9.4 9.8 9.9 10.2 10.7 9.9 10.2 10.6 11.3 11.8 12.4 13.2 14.0 14.3 14.8 15.3 15.7 16.2 16.8 17.4 18.1
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Scenario Sensitivity
Case
Rates
(¢/kWh) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2 BASE CCA gen 7.2 7.3 7.3 7.6 7.8 8.0 8.0 8.3 8.6 9.1 9.5 10.0 10.6 10.8 11.1 11.3 11.6 11.9 12.1 12.4 12.7
2 BASE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
2 BASE CCA Res Fund 0.6 0.8 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1
2 BASE PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
2 LP CCA gen 7.3 7.4 7.4 7.6 7.8 8.1 8.1 8.3 8.7 9.1 9.6 10.1 10.6 10.9 11.1 11.4 11.7 11.9 12.2 12.5 12.8
2 LP Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
2 LP CCA Res Fund 0.5 0.9 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1
2 LP PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
2 LOC CCA gen 7.2 7.3 7.3 7.6 7.8 8.0 8.0 8.3 8.6 9.1 9.5 10.0 10.6 10.8 11.1 11.3 11.6 11.9 12.1 12.4 12.7
2 LOC Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
2 LOC CCA Res Fund 0.6 0.8 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1
2 LOC PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
2 RPS CCA gen 7.3 7.5 7.6 8.2 8.5 9.1 9.2 9.5 10.0 10.5 11.0 11.6 12.3 12.5 12.8 13.1 13.4 13.7 14.0 14.4 14.7
2 RPS Exit fees 2.4 1.9 2.3 1.6 1.6 1.5 1.3 1.1 0.9 0.7 0.6 0.5 0.5 0.4 0.3 0.1 0.0 0.0 0.0 0.0 0.0
2 RPS CCA Res Fund 0.5 0.9 0.4 0.1 0.1 0.1 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1
2 RPS PG&E gen 10.1 10.6 10.7 11.3 11.6 11.5 11.4 11.1 11.5 12.2 12.9 13.8 14.9 15.7 16.5 17.3 17.3 17.8 18.4 18.7 19.4
2 GAS CCA gen 8.0 8.3 8.7 9.0 9.3 8.9 9.0 9.2 9.6 9.9 10.3 10.8 11.3 11.6 11.9 12.2 12.5 12.8 13.1 13.4 13.8
2 GAS Exit fees 2.2 2.6 2.7 2.8 2.6 3.4 2.4 1.7 0.8 0.7 0.7 0.6 0.5 0.3 0.2 0.1 0.1 0.1 0.1 0.1 0.1
2 GAS CCA Res Fund 0.3 0.0 -0.1 0.0 1.4 -1.4 0.0 1.4 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1
2 GAS PG&E gen 10.5 10.9 11.0 11.4 11.9 11.0 11.3 11.8 12.3 12.9 13.5 14.3 15.3 15.4 15.8 16.2 16.7 17.1 17.7 18.3 19.0
2 LPGE CCA gen 7.2 7.3 7.3 7.6 7.8 8.0 8.0 8.3 8.6 9.1 9.5 10.0 10.6 10.8 11.1 11.3 11.6 11.9 12.1 12.4 12.7
2 LPGE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
2 LPGE CCA Res Fund 0.0 1.1 0.0 0.4 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1
2 LPGE PG&E gen 9.1 9.5 9.6 10.1 10.4 10.2 10.2 9.8 10.2 10.7 11.4 12.1 13.0 13.2 13.6 14.0 14.5 14.9 15.3 15.8 16.4
2 PCIA CCA gen 7.2 7.3 7.3 7.6 7.8 8.0 8.0 8.3 8.6 9.1 9.5 10.0 10.6 10.8 11.1 11.3 11.6 11.9 12.1 12.4 12.7
2 PCIA Exit fees 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4
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2 PCIA CCA Res Fund 0.6 0.8 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1
2 PCIA PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
2 STRS CCA gen 8.2 8.6 9.0 9.7 9.9 10.1 10.2 10.5 10.9 11.4 11.9 12.4 13.0 13.4 13.7 14.0 14.4 14.7 15.1 15.4 15.8
2 STRS Exit fees 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
2 STRS CCA Res Fund 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
2 STRS PG&E gen 9.4 9.8 9.9 10.2 10.7 9.9 10.2 10.6 11.3 11.8 12.4 13.2 14.0 14.3 14.8 15.3 15.7 16.2 16.8 17.4 18.1
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Scenario Sensitivity
Case
Rates
(¢/kWh) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 3 BASE CCA gen 7.0 7.1 7.2 7.5 7.8 8.1 8.2 8.5 8.9 9.5 10.0 10.5 11.1 11.5 11.8 12.1 12.4 12.8 13.1 13.4 13.8
3 BASE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
3 BASE CCA Res Fund 0.7 0.7 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 BASE PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
3 LP CCA gen 7.2 7.3 7.3 7.6 7.9 8.2 8.3 8.5 8.9 9.5 10.0 10.5 11.1 11.5 11.8 12.1 12.4 12.8 13.1 13.4 13.8
3 LP Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
3 LP CCA Res Fund 0.6 0.8 0.4 0.1 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 LP PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
3 LOC CCA gen 7.1 7.2 7.3 7.7 8.0 8.3 8.5 8.7 9.3 9.9 10.4 11.0 11.6 12.0 12.3 12.6 13.0 13.3 13.6 14.0 14.4
3 LOC Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
3 LOC CCA Res Fund 0.7 0.7 0.4 0.1 0.1 0.1 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 LOC PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
3 RPS CCA gen 7.1 7.2 7.4 7.9 8.3 8.9 9.1 9.4 10.0 10.6 11.2 11.8 12.5 12.9 13.3 13.7 14.1 14.4 14.8 15.2 15.6
3 RPS Exit fees 2.4 1.9 2.3 1.6 1.6 1.5 1.3 1.1 0.9 0.7 0.6 0.5 0.5 0.4 0.3 0.1 0.0 0.0 0.0 0.0 0.0
3 RPS CCA Res Fund 0.7 0.7 0.4 0.1 0.1 0.1 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 RPS PG&E gen 10.1 10.6 10.7 11.3 11.6 11.5 11.4 11.1 11.5 12.2 12.9 13.8 14.9 15.7 16.5 17.3 17.3 17.8 18.4 18.7 19.4
3 GAS CCA gen 8.1 8.5 8.9 9.3 9.5 9.6 9.8 10.0 10.5 11.0 11.5 12.0 12.6 13.0 13.3 13.7 14.1 14.5 14.9 15.3 15.8
3 GAS Exit fees 2.2 2.6 2.7 2.8 2.6 3.4 2.4 1.7 0.8 0.7 0.7 0.6 0.5 0.3 0.2 0.1 0.1 0.1 0.1 0.1 0.1
3 GAS CCA Res Fund 0.2 -0.1 0.0 0.0 0.0 0.0 0.0 1.5 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 GAS PG&E gen 10.5 10.9 11.0 11.4 11.9 11.0 11.3 11.8 12.3 12.9 13.5 14.3 15.3 15.4 15.8 16.2 16.7 17.1 17.7 18.3 19.0
3 LPGE CCA gen 7.0 7.1 7.2 7.5 7.8 8.1 8.2 8.5 8.9 9.5 10.0 10.5 11.1 11.5 11.8 12.1 12.4 12.8 13.1 13.4 13.8
3 LPGE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
3 LPGE CCA Res Fund 0.0 1.1 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 LPGE PG&E gen 9.1 9.5 9.6 10.1 10.4 10.2 10.2 9.8 10.2 10.7 11.4 12.1 13.0 13.2 13.6 14.0 14.5 14.9 15.3 15.8 16.4
3 PCIA CCA gen 7.0 7.1 7.2 7.5 7.8 8.1 8.2 8.5 8.9 9.5 10.0 10.5 11.1 11.5 11.8 12.1 12.4 12.8 13.1 13.4 13.8
3 PCIA Exit fees 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4
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3 PCIA CCA Res Fund 0.7 0.7 0.4 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
3 PCIA PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
3 STRS CCA gen 8.3 8.8 9.2 9.8 10.2 10.8 11.0 11.4 12.1 12.8 13.3 14.0 14.7 15.2 15.7 16.2 16.7 17.1 17.6 18.1 18.6
3 STRS Exit fees 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
3 STRS CCA Res Fund 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
3 STRS PG&E gen 9.4 9.8 9.9 10.2 10.7 9.9 10.2 10.6 11.3 11.8 12.4 13.2 14.0 14.3 14.8 15.3 15.7 16.2 16.8 17.4 18.1
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Scenario Sensitivity
Case
Rates
(¢/kWh) 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 4 BASE CCA gen 7.3 7.4 7.5 7.9 8.2 8.6 8.8 9.3 10.0 10.7 11.2 11.8 12.5 12.7 13.0 13.2 13.5 13.8 14.1 14.3 14.6
4 BASE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
4 BASE CCA Res Fund 0.5 0.8 0.4 0.1 0.1 0.1 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1
4 BASE PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
4 LP CCA gen 7.4 7.5 7.6 7.9 8.2 8.6 8.8 9.3 9.9 10.7 11.2 11.7 12.3 12.6 12.8 13.1 13.3 13.6 13.9 14.2 14.5
4 LP Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
4 LP CCA Res Fund 0.4 0.9 0.4 0.1 0.1 0.1 0.0 0.1 0.1 0.1 0.1 0.1 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1
4 LP PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
4 LOC CCA gen 7.3 7.5 7.6 8.0 8.4 8.9 9.2 9.8 10.6 11.4 12.0 12.6 13.3 13.5 13.8 14.1 14.4 14.7 14.9 15.2 15.6
4 LOC Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
4 LOC CCA Res Fund 0.5 0.9 0.4 0.1 0.1 0.1 0.1 -0.2 -0.1 -0.3 0.0 1.2 0.1 0.0 0.0 0.0 0.1 0.1 0.1 0.1 0.1
4 LOC PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
4 RPS CCA gen 7.3 7.6 7.8 8.5 9.0 9.9 10.3 11.0 11.8 12.7 13.4 14.1 14.9 15.2 15.5 15.8 16.1 16.5 16.8 17.1 17.5
4 RPS Exit fees 2.4 1.9 2.3 1.6 1.6 1.5 1.3 1.1 0.9 0.7 0.6 0.5 0.5 0.4 0.3 0.1 0.0 0.0 0.0 0.0 0.0
4 RPS CCA Res Fund 0.4 0.9 0.4 0.1 0.1 0.1 -0.2 -0.9 -0.3 0.0 0.0 0.0 0.0 2.3 0.1 0.1 0.1 0.1 0.1 0.1 0.1
4 RPS PG&E gen 10.1 10.6 10.7 11.3 11.6 11.5 11.4 11.1 11.5 12.2 12.9 13.8 14.9 15.7 16.5 17.3 17.3 17.8 18.4 18.7 19.4
4 GAS CCA gen 8.0 8.4 8.8 9.1 9.4 9.5 9.8 10.3 11.0 11.7 12.2 12.7 13.3 13.6 13.9 14.3 14.6 14.9 15.2 15.5 15.9
4 GAS Exit fees 2.2 2.6 2.7 2.8 2.6 3.4 2.4 1.7 0.8 0.7 0.7 0.6 0.5 0.3 0.2 0.1 0.1 0.1 0.1 0.1 0.1
4 GAS CCA Res Fund 0.2 -0.1 0.0 0.0 0.0 0.0 0.0 0.0 1.6 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1 0.1
4 GAS PG&E gen 10.5 10.9 11.0 11.4 11.9 11.0 11.3 11.8 12.3 12.9 13.5 14.3 15.3 15.4 15.8 16.2 16.7 17.1 17.7 18.3 19.0
4 LPGE CCA gen 7.3 7.4 7.5 7.9 8.2 8.6 8.8 9.3 10.0 10.7 11.2 11.8 12.5 12.7 13.0 13.2 13.5 13.8 14.1 14.3 14.6
4 LPGE Exit fees 2.4 1.9 2.3 1.7 1.7 1.6 1.5 1.3 0.9 0.8 0.7 0.6 0.5 0.3 0.2 0.1 0.0 0.0 0.0 0.0 0.0
4 LPGE CCA Res Fund 0.0 1.1 -0.2 0.7 0.1 0.1 -0.1 -0.8 -0.4 0.0 0.0 0.0 0.0 1.9 0.0 0.0 0.0 0.0 0.0 0.1 0.1
4 LPGE PG&E gen 9.1 9.5 9.6 10.1 10.4 10.2 10.2 9.8 10.2 10.7 11.4 12.1 13.0 13.2 13.6 14.0 14.5 14.9 15.3 15.8 16.4
4 PCIA CCA gen 7.3 7.4 7.5 7.9 8.2 8.6 8.8 9.3 10.0 10.7 11.2 11.8 12.5 12.7 13.0 13.2 13.5 13.8 14.1 14.3 14.6
4 PCIA Exit fees 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4 2.4
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4 PCIA CCA Res Fund 0.5 0.8 0.4 0.1 0.1 0.1 0.0 -0.8 -0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 0.0 0.0 0.1 0.1
4 PCIA PG&E gen 10.1 10.6 10.7 11.3 11.6 11.4 11.3 10.9 11.3 11.9 12.6 13.4 14.4 14.7 15.1 15.6 16.1 16.5 17.1 17.6 18.3
4 STRS CCA gen 8.3 8.8 9.3 10.0 10.5 11.4 11.8 12.7 13.6 14.7 15.4 16.1 16.8 17.2 17.6 18.0 18.4 18.9 19.3 19.7 20.2
4 STRS Exit fees 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
4 STRS CCA Res Fund 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
4 STRS PG&E gen 9.4 9.8 9.9 10.2 10.7 9.9 10.2 10.6 11.3 11.8 12.4 13.2 14.0 14.3 14.8 15.3 15.7 16.2 16.8 17.4 18.1
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Appendix E. Greenhouse Gas Emissions and Costs
In Chapter 3 of the report, MRW provided an estimate of Costa County CCA’s annual
Greenhouse Gas (GHG) emissions and compared these with the emissions for the same load
under the PG&E supply portfolio. The methodology used to calculate both figures is included in
this appendix, along with an estimate of Costa County CCA’s cost of emissions from purchased
power (“indirect emissions”).
Methodology for calculating Costa County CCA’s indirect GHG emissions
GHG emissions for Costa County CCA will be indirect since the CCA does not plan to generate
its own power (i.e., the emissions are embedded in fossil-fuel power that the CCA purchases).
These emissions are estimated based on (1) a forecast of the emissions rate for Costa County
CCA’s fossil generation supply and (2) a forecast of the amount of Costa County CCA’s fossil
generation supply, developed by subtracting expected renewable and hydroelectric generation
from the projected wholesale power requirement to serve the CCA’s load.33
MRW calculated the emissions rate for Costa County CCA’s fossil generation supply by
estimating the amount of natural gas that will need to be burned to generate the CCA’s fossil
generation and the GHG emissions rate for natural gas combustion.34 The amount of natural gas
needed was estimated based on the average heat rate for the marginal generation plants on the
CAISO system. MRW used public data from CAISO’s OASIS platform and Platt’s Gas Daily
reports to calculate this average heat rate for 2015.35 MRW extended the forecast to 2030 using
the expected changes to the average heat rate in California from the EIA’s 2016 Annual Energy
Outlook.36
MRW estimated the total annual GHG emissions for the Costa County CCA program as a
product of the total energy purchased at wholesale electric market (kWh) and the rate of GHG
emissions (tonnes CO2-equivalent/kWh).
33 MRW assumed no GHG emissions for the renewable and hydroelectric supply.
34 The GHG emissions rate for natural gas combustion is obtained from U.S. EIA. Electric Power Annual (EPA),
February 16, 2016, Table A.3. https://www.eia.gov/electricity/annual/html/epa_a_03.html
35 MRW calculated the average heat rate of the marginal generation plants in 2015 by dividing the monthly average
wholesale electric market price, net of operations and maintenance costs and GHG emissions costs, by the monthly
average natural gas price. For the electricity prices, we used the average of the 2015 hourly locational marginal price
for node TH_NP15_GEN-APND; for the natural gas prices, we used the average of burnertip natural gas price for
PG&E.
36 U.S. Energy Information Administration. “2016 Annual Energy Outlook,” Table 55.20, Western Electricity
Coordinating Council. (Note that EIA does not provide a forecast of the marginal heat rate.)
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Methodology for calculating GHG emissions under PG&E’s supply portfolio
MRW calculated the GHG emissions for the Costa County CCA load under the PG&E supply
portfolio by summing the emissions from all resources in PG&E’s portfolio. MRW assumed no
GHG emissions from renewable power, hydroelectric power, or nuclear generation. In order to
maintain a consistent comparison, MRW used the same emissions rate to calculate the emissions
from PG&E’s fossil-fuel power as used for the Costa County CCA wholesale market purchases.
In order to support the analysis on Chapter 3 of the report, Figure 2 shows the PG&E portfolio.
Before the closure of the Diablo Canyon, MRW estimated 80%-90% of PG&E’s generation
portfolio based on non-fuel-fired resources. After 2025, the non-fuel-fired resources share falls to
70% according MRW estimates.
Figure 2 PG&E’s generation portfolio37
GHG allowance prices and GHG indirect costs
37 Before 2025 the hydroelectric generation is below its potential because MRW estimated that PG&E sells the over-
procurement in hydroelectric power. MRW has assumed a minimum of fuel -fired generation to facilitate the RPS
integration according to PG&E’s Diablo Canyon retirement application, A.16 -08-006. Table 2-3. In addition, after
2026 MRW estimated the price of the wholesale electric market below PG&E’s new RPS prices. In those
conditions, according to MRW assumptions, PG&E would procure up to 50% of its portfolio from renewable
resources.
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MRW developed a forecast of the prices for GHG allowances based on the auction floor price
stipulated by the ARB’s cap-and-trade regulation, consistent with recent auction outcomes.38
Table 2 GHG Allowances price, $ per allowance39
2017 2018 2019 2025 2030 2035 2038
$/tonne 13.2 14.7 15.9 24.4 34.7 49.8 61.8
MRW used these GHG allowances prices to calculate both PG&E’s GHG allowances costs
(direct and indirect), which are included in the PG&E rate forecast, and Costa County CCA’s
indirect GHG costs. The indirect GHG costs for Costa County CCA will be included in the cost
of the wholesale market energy purchases. MRW estimated that these costs will be, on average,
$12 per MWh delivered over the 2018-2038 period.
38 California Code of Regulations, Title 17, Article 5, Section 95911.
39 For 2017, the amount listed corresponds to the GHG allowance price for PG&E according to the most recent
ERRA 2017 update. Pacific Gas & Electric ERRA 2017, A.16-06-003, Testimony November 2, 2016, Table 12-1.
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Appendix F. Macroeconomic Analysis
About the REMI Policy Insight Model
A software analysis forecasting model developed by Regional Economic Models, Inc. (REMI) of
Amherst Massachusetts in the mid 1980’s. It has a broad national customer base among public
agencies, academic institutions, and the private-sector. It is also used in Canada (NRCan), and
among other international clients. The model configuration used for this study consisted of 18
aggregate private-sector industries, plus a farm sector, a combined state/local government sector
and two federal government sectors.
Economic Impacts Identified with the REMI Model
The REMI Model
Alternative Forecast
Compare Forecasts
Control Forecast
What are the
effects of the
Proposed
Action?
Baseline values
for all Policy
Variables Policy
Action
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In the above figure, the central box “The REMI model” is the engine for predicting the economic
and demographic dimensions of a region-of-impact (here Costa County County) under no-action
(or Control forecast) and with a proposed CCA (alternative forecast). The engine is a
combination structural econometric model, part input-output transactions, all with general
equilibrium features – meaning an economy can encounter a disruption (positive or negative),
and over time (typically 1-3 years depending on the scale of the region and the size of the shock)
re-adjust back to an equilibrium. The diagram below depicts the organization of the REMI
regional model in terms of the major blocks functioning in an economy and the arrows denote
the feedback accounted for. Keep in mind this portrayal is at a very high-level, sparing the
industry-specific details. Scenario specific changes are inserted through policy variable levers
into the appropriate block of the model. There is another important dimension of economic
response for the key region-of-impact that effectively layers on top of the below diagram –
interactions with another regional economy. That additional region - rest of California -was
explicitly modeled at the same time. The REMI model captures the flows of monetized goods
and services, and commuter labor between regions when one (or both) is shocked by introduction
of a CCA.
Core Logic of the REMI Model
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Appendix G. Proforma
Scenario 1
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038
Expenses
Cost of Power (including losses)$73,495,453 $151,069,291 $238,312,375 $248,611,457 $257,237,071 $265,886,720 $274,183,543 $279,728,463 $294,209,869 $310,824,883 $329,903,546 $350,515,984 $373,621,644 $386,946,608 $399,254,590 $411,812,091 $425,651,977 $439,658,506 $454,135,582 $468,721,683 $484,831,280
O&M/A&G Costs $9,081,989 $11,047,477 $14,037,456 $14,312,982 $14,596,957 $14,871,929 $15,146,845 $15,425,482 $15,722,408 $16,025,074 $16,333,641 $16,648,197 $16,968,859 $17,295,746 $17,628,978 $17,968,678 $18,314,999 $18,668,042 $19,027,938 $19,394,819 $19,768,820
Energy Efficiency Programming Costs
Total Expenses $82,577,443 $162,116,767 $252,349,831 $262,924,440 $271,834,028 $280,758,650 $289,330,388 $295,153,945 $309,932,277 $326,849,957 $346,237,187 $367,164,181 $390,590,503 $404,242,354 $416,883,567 $429,780,769 $443,966,976 $458,326,548 $473,163,520 $488,116,502 $504,600,100
Debt Service $0 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Revenue Requirement $82,577,443 $167,605,774 $257,838,838 $268,413,446 $277,323,035 $286,247,656 $289,330,388 $295,153,945 $309,932,277 $326,849,957 $346,237,187 $367,164,181 $390,590,503 $404,242,354 $416,883,567 $429,780,769 $443,966,976 $458,326,548 $473,163,520 $488,116,502 $504,600,100
Total Load, MWh 1,177,121 2,366,944 3,607,181 3,623,598 3,641,698 3,652,169 3,659,921 3,666,956 3,680,582 3,694,258 3,707,985 3,721,763 3,735,593 3,749,473 3,763,406 3,777,390 3,791,426 3,805,514 3,819,655 3,833,848 3,848,093
Contra Costa CCA Customer Charges, $/MWh (before Reserve Fund Adjustment)
Average Contra Costa CCA generation $70.2 $70.8 $71.5 $74.1 $76.2 $78.4 $79.1 $80.5 $84.2 $88.5 $93.4 $98.7 $104.6 $107.8 $110.8 $113.8 $117.1 $120.4 $123.9 $127.3 $131.1
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $93.8 $89.9 $94.3 $90.6 $92.7 $94.1 $93.6 $93.1 $93.3 $96.4 $100.4 $104.6 $109.7 $110.9 $112.4 $114.4 $117.1 $120.4 $123.9 $127.3 $131.1
PG&E average gen rate for CCA load, $/MWh $101.5 $105.7 $106.6 $112.7 $115.5 $113.8 $113.3 $109.2 $113.2 $119.2 $126.3 $134.2 $144.0 $146.7 $151.0 $155.7 $160.8 $165.0 $170.5 $176.0 $182.5
Reserve Fund Adjustment
Target $12,386,616 $25,140,866 $38,675,826 $40,262,017 $41,598,455 $42,937,148 $43,399,558 $44,273,092 $46,489,842 $49,027,494 $51,935,578 $55,074,627 $58,588,575 $60,636,353 $62,532,535 $64,467,115 $66,595,046 $68,748,982 $70,974,528 $73,217,475 $75,690,015
Reserve Fund Adjustment
Potential Reserve potential $9,037,817 $37,373,117 $44,318,310 $79,873,437 $82,994,739 $72,190,684 $72,076,358 $58,860,584 $73,135,250 $84,142,452 $96,221,651 $110,201,860 $128,194,145 $134,215,487 $145,270,805 $156,288,619 $165,801,447 $169,687,264 $178,229,235 $186,523,044 $197,789,460
Potential Reserve additions $9,037,817 $16,103,049 $13,534,960 $1,586,191 $1,336,438 $1,338,693 $462,410 $873,533 $2,216,750 $2,537,652 $2,908,084 $3,139,049 $3,513,948 $2,047,778 $1,896,182 $1,934,580 $2,127,931 $2,153,936 $2,225,546 $2,242,947 $2,472,540
Subtractions from reserve fund $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Reserve fund total $9,037,817 $25,140,866 $38,675,826 $40,262,017 $41,598,455 $42,937,148 $43,399,558 $44,273,092 $46,489,842 $49,027,494 $51,935,578 $55,074,627 $58,588,575 $60,636,353 $62,532,535 $64,467,115 $66,595,046 $68,748,982 $70,974,528 $73,217,475 $75,690,015
Contra Costa CCA Customer Charges, $/MWh (with Reserve Fund Adjustment)
Rate adjustment from Reserve Fund $7.7 $6.8 $3.8 $0.4 $0.4 $0.4 $0.1 $0.2 $0.6 $0.7 $0.8 $0.8 $0.9 $0.5 $0.5 $0.5 $0.6 $0.6 $0.6 $0.6 $0.6
Average Contra Costa CCA rate $77.8 $77.6 $75.2 $74.5 $76.5 $78.7 $79.2 $80.7 $84.8 $89.2 $94.2 $99.5 $105.5 $108.4 $111.3 $114.3 $117.7 $121.0 $124.5 $127.9 $131.8
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $101.5 $96.7 $98.1 $91.1 $93.1 $94.4 $93.8 $93.4 $93.9 $97.1 $101.2 $105.5 $110.6 $111.5 $112.9 $114.9 $117.7 $121.0 $124.5 $127.9 $131.8
Note: Reserve fund revenue is used to reduce CCA rates if (i) CCA rates are lower than PG&E rates or (ii) the reserve fund reaches the ceiling of half a year of expenses.
Contra Costa CCA CO2 emissions
Emissions (Tonnes/MWh)0.04 0.03 0.02 0.02 0.02 0.02 0.02 0.04 0.05 0.05 0.05 0.05 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04
Total emissions (Tonnes)48,104 76,449 70,394 71,051 71,298 72,351 73,983 158,002 195,517 194,741 195,332 196,074 197,642 162,803 163,997 165,333 166,460 167,595 168,634 170,197 171,328
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Scenario 2
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038
Expenses
Cost of Power (including losses)$75,667,208 $155,562,573 $244,603,605 $253,936,224 $262,178,133 $270,821,465 $279,147,605 $288,420,808 $302,569,437 $318,621,199 $336,840,252 $356,586,893 $378,456,407 $388,844,347 $399,378,659 $410,314,502 $421,560,027 $432,993,327 $444,699,721 $456,541,793 $469,291,025
O&M/A&G Costs $9,081,989 $11,047,477 $14,037,456 $14,312,982 $14,596,957 $14,871,929 $15,146,845 $15,425,482 $15,722,408 $16,025,074 $16,333,641 $16,648,197 $16,968,859 $17,295,746 $17,628,978 $17,968,678 $18,314,999 $18,668,042 $19,027,938 $19,394,819 $19,768,820
Energy Efficiency Programming Costs
Total Expenses $84,749,197 $166,610,049 $258,641,061 $268,249,207 $276,775,090 $285,693,394 $294,294,450 $303,846,289 $318,291,846 $334,646,273 $353,173,892 $373,235,090 $395,425,266 $406,140,093 $417,007,637 $428,283,180 $439,875,026 $451,661,369 $463,727,659 $475,936,612 $489,059,845
Debt Service $0 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Revenue Requirement $84,749,197 $172,099,056 $264,130,067 $273,738,213 $282,264,096 $291,182,400 $294,294,450 $303,846,289 $318,291,846 $334,646,273 $353,173,892 $373,235,090 $395,425,266 $406,140,093 $417,007,637 $428,283,180 $439,875,026 $451,661,369 $463,727,659 $475,936,612 $489,059,845
Total Load, MWh 1,177,121 2,366,944 3,607,181 3,623,598 3,641,698 3,652,169 3,659,921 3,666,956 3,680,582 3,694,258 3,707,985 3,721,763 3,735,593 3,749,473 3,763,406 3,777,390 3,791,426 3,805,514 3,819,655 3,833,848 3,848,093
Contra Costa CCA Customer Charges, $/MWh (before Reserve Fund Adjustment)
Average Contra Costa CCA generation $72.0 $72.7 $73.2 $75.5 $77.5 $79.7 $80.4 $82.9 $86.5 $90.6 $95.2 $100.3 $105.9 $108.3 $110.8 $113.4 $116.0 $118.7 $121.4 $124.1 $127.1
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $95.7 $91.8 $96.1 $92.1 $94.1 $95.4 $95.0 $95.5 $95.6 $98.5 $102.2 $106.2 $111.0 $111.4 $112.5 $114.0 $116.0 $118.7 $121.4 $124.1 $127.1
PG&E average gen rate for CCA load, $/MWh $101.5 $105.7 $106.6 $112.7 $115.5 $113.8 $113.3 $109.2 $113.2 $119.2 $126.3 $134.2 $144.0 $146.7 $151.0 $155.7 $160.8 $165.0 $170.5 $176.0 $182.5
Reserve Fund Adjustment
Target $12,712,380 $25,814,858 $39,619,510 $41,060,732 $42,339,614 $43,677,360 $44,144,167 $45,576,943 $47,743,777 $50,196,941 $52,976,084 $55,985,264 $59,313,790 $60,921,014 $62,551,146 $64,242,477 $65,981,254 $67,749,205 $69,559,149 $71,390,492 $73,358,977
Reserve Fund Adjustment
Potential Reserve potential $6,866,063 $32,879,835 $38,027,080 $74,548,670 $78,053,677 $67,255,940 $67,112,296 $50,168,239 $64,775,682 $76,346,136 $89,284,946 $104,130,951 $123,359,382 $132,317,748 $145,146,736 $157,786,207 $169,893,397 $176,352,443 $187,665,096 $198,702,934 $213,329,715
Potential Reserve additions $6,866,063 $18,948,796 $13,804,652 $1,441,222 $1,278,883 $1,337,746 $466,807 $1,432,776 $2,166,833 $2,453,164 $2,779,143 $3,009,180 $3,328,526 $1,607,224 $1,630,132 $1,691,331 $1,738,777 $1,767,951 $1,809,944 $1,831,343 $1,968,485
Subtractions from reserve fund $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Reserve fund total $6,866,063 $25,814,858 $39,619,510 $41,060,732 $42,339,614 $43,677,360 $44,144,167 $45,576,943 $47,743,777 $50,196,941 $52,976,084 $55,985,264 $59,313,790 $60,921,014 $62,551,146 $64,242,477 $65,981,254 $67,749,205 $69,559,149 $71,390,492 $73,358,977
Contra Costa CCA Customer Charges, $/MWh (with Reserve Fund Adjustment)
Rate adjustment from Reserve Fund $5.8 $8.0 $3.8 $0.4 $0.4 $0.4 $0.1 $0.4 $0.6 $0.7 $0.7 $0.8 $0.9 $0.4 $0.4 $0.4 $0.5 $0.5 $0.5 $0.5 $0.5
Average Contra Costa CCA rate $77.8 $80.7 $77.1 $75.9 $77.9 $80.1 $80.5 $83.3 $87.1 $91.2 $96.0 $101.1 $106.7 $108.7 $111.2 $113.8 $116.5 $119.2 $121.9 $124.6 $127.6
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $101.5 $99.8 $99.9 $92.5 $94.4 $95.8 $95.1 $95.9 $96.1 $99.2 $103.0 $107.1 $111.9 $111.9 $112.9 $114.4 $116.5 $119.2 $121.9 $124.6 $127.6
Note: Reserve fund revenue is used to reduce CCA rates if (i) CCA rates are lower than PG&E rates or (ii) the reserve fund reaches the ceiling of half a year of expenses.
Contra Costa CCA CO2 emissions
Emissions (Tonnes/MWh)0.04 0.03 0.02 0.02 0.02 0.02 0.02 0.04 0.05 0.05 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04
Total emissions (Tonnes)48,104 76,449 70,394 71,051 71,298 72,351 73,983 158,002 195,517 194,741 179,036 161,586 144,182 144,830 145,465 146,223 146,793 147,369 147,857 148,803 149,369
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G- 3
Scenario 3
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038
Expenses
Cost of Power (including losses)$73,821,840 $152,481,196 $241,777,679 $253,556,146 $264,094,600 $275,032,738 $285,950,513 $294,594,258 $312,594,056 $333,441,830 $353,576,083 $374,999,146 $398,607,664 $412,772,050 $425,891,475 $439,246,520 $452,905,747 $466,709,445 $480,979,253 $495,335,405 $511,232,007
O&M/A&G Costs $9,081,989 $11,047,477 $14,037,456 $14,312,982 $14,596,957 $14,871,929 $15,146,845 $15,425,482 $15,722,408 $16,025,074 $16,333,641 $16,648,197 $16,968,859 $17,295,746 $17,628,978 $17,968,678 $18,314,999 $18,668,042 $19,027,938 $19,394,819 $19,768,820
Energy Efficiency Programming Costs
Total Expenses $82,903,829 $163,528,673 $255,815,136 $267,869,129 $278,691,558 $289,904,667 $301,097,358 $310,019,739 $328,316,464 $349,466,905 $369,909,723 $391,647,343 $415,576,523 $430,067,796 $443,520,453 $457,215,198 $471,220,746 $485,377,487 $500,007,190 $514,730,224 $531,000,828
Debt Service $0 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Revenue Requirement $82,903,829 $169,017,679 $261,304,142 $273,358,135 $284,180,564 $295,393,673 $301,097,358 $310,019,739 $328,316,464 $349,466,905 $369,909,723 $391,647,343 $415,576,523 $430,067,796 $443,520,453 $457,215,198 $471,220,746 $485,377,487 $500,007,190 $514,730,224 $531,000,828
Total Load, MWh 1,177,121 2,366,944 3,607,181 3,623,598 3,641,698 3,652,169 3,659,921 3,666,956 3,680,582 3,694,258 3,707,985 3,721,763 3,735,593 3,749,473 3,763,406 3,777,390 3,791,426 3,805,514 3,819,655 3,833,848 3,848,093
Contra Costa CCA Customer Charges, $/MWh (before Reserve Fund Adjustment)
Average Contra Costa CCA generation $70.4 $71.4 $72.4 $75.4 $78.0 $80.9 $82.3 $84.5 $89.2 $94.6 $99.8 $105.2 $111.2 $114.7 $117.9 $121.0 $124.3 $127.5 $130.9 $134.3 $138.0
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $94.1 $90.5 $95.3 $92.0 $94.6 $96.6 $96.8 $97.2 $98.3 $102.6 $106.8 $111.2 $116.4 $117.8 $119.5 $121.6 $124.3 $127.5 $130.9 $134.3 $138.0
PG&E average gen rate for CCA load, $/MWh $101.5 $105.7 $106.6 $112.7 $115.5 $113.8 $113.3 $109.2 $113.2 $119.2 $126.3 $134.2 $144.0 $146.7 $151.0 $155.7 $160.8 $165.0 $170.5 $176.0 $182.5
Reserve Fund Adjustment
Target $12,435,574 $25,352,652 $39,195,621 $41,003,720 $42,627,085 $44,309,051 $45,164,604 $46,502,961 $49,247,470 $52,420,036 $55,486,459 $58,747,101 $62,336,479 $64,510,169 $66,528,068 $68,582,280 $70,683,112 $72,806,623 $75,001,079 $77,209,534 $79,650,124
Reserve Fund Adjustment
Potential Reserve potential $8,711,430 $35,961,212 $40,853,005 $74,928,748 $76,137,209 $63,044,667 $60,309,388 $43,994,789 $54,751,063 $61,525,504 $72,549,115 $85,718,698 $103,208,125 $108,390,045 $118,633,920 $128,854,190 $138,547,677 $142,636,325 $151,385,564 $159,909,323 $171,388,732
Potential Reserve additions $8,711,430 $16,641,221 $13,842,969 $1,808,099 $1,623,364 $1,681,966 $855,553 $1,338,357 $2,744,509 $3,172,566 $3,066,423 $3,260,643 $3,589,377 $2,173,691 $2,017,899 $2,054,212 $2,100,832 $2,123,511 $2,194,456 $2,208,455 $2,440,591
Subtractions from reserve fund $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Reserve fund total $8,711,430 $25,352,652 $39,195,621 $41,003,720 $42,627,085 $44,309,051 $45,164,604 $46,502,961 $49,247,470 $52,420,036 $55,486,459 $58,747,101 $62,336,479 $64,510,169 $66,528,068 $68,582,280 $70,683,112 $72,806,623 $75,001,079 $77,209,534 $79,650,124
Contra Costa CCA Customer Charges, $/MWh (with Reserve Fund Adjustment)
Rate adjustment from Reserve Fund $7.4 $7.0 $3.8 $0.5 $0.4 $0.5 $0.2 $0.4 $0.7 $0.9 $0.8 $0.9 $1.0 $0.6 $0.5 $0.5 $0.6 $0.6 $0.6 $0.6 $0.6
Average Contra Costa CCA rate $77.8 $78.4 $76.3 $75.9 $78.5 $81.3 $82.5 $84.9 $89.9 $95.5 $100.6 $106.1 $112.2 $115.3 $118.4 $121.6 $124.8 $128.1 $131.5 $134.8 $138.6
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $101.5 $97.5 $99.1 $92.5 $95.1 $97.0 $97.1 $97.5 $99.0 $103.4 $107.6 $112.1 $117.3 $118.4 $120.1 $122.2 $124.8 $128.1 $131.5 $134.8 $138.6
Note: Reserve fund revenue is used to reduce CCA rates if (i) CCA rates are lower than PG&E rates or (ii) the reserve fund reaches the ceiling of half a year of expenses.
Contra Costa CCA CO2 emissions
Emissions (Tonnes/MWh)0.04 0.03 0.02 0.02 0.02 0.02 0.02 0.04 0.05 0.05 0.05 0.05 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04
Total emissions (Tonnes)48,104 76,449 70,394 71,051 71,298 72,351 73,983 158,002 195,517 194,741 195,332 196,074 197,642 162,803 163,997 165,333 166,460 167,595 168,634 170,197 171,328
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G- 4
Scenario 4
2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038
Expenses
Cost of Power (including losses)$76,298,847 $158,353,376 $251,613,719 $264,966,652 $277,857,664 $291,930,494 $307,270,279 $327,315,270 $351,172,361 $379,984,062 $400,711,371 $422,894,433 $448,135,664 $459,135,226 $470,252,191 $481,804,642 $493,681,157 $505,723,842 $518,057,626 $530,499,789 $543,962,195
O&M/A&G Costs $9,081,989 $11,047,477 $14,037,456 $14,312,982 $14,596,957 $14,871,929 $15,146,845 $15,425,482 $15,722,408 $16,025,074 $16,333,641 $16,648,197 $16,968,859 $17,295,746 $17,628,978 $17,968,678 $18,314,999 $18,668,042 $19,027,938 $19,394,819 $19,768,820
Energy Efficiency Programming Costs
Total Expenses $85,380,836 $169,400,852 $265,651,176 $279,279,634 $292,454,621 $306,802,423 $322,417,124 $342,740,752 $366,894,769 $396,009,136 $417,045,012 $439,542,630 $465,104,523 $476,430,971 $487,881,169 $499,773,320 $511,996,156 $524,391,884 $537,085,564 $549,894,608 $563,731,016
Debt Service $0 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $5,489,006 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total Revenue Requirement $85,380,836 $174,889,859 $271,140,182 $284,768,640 $297,943,628 $312,291,430 $322,417,124 $342,740,752 $366,894,769 $396,009,136 $417,045,012 $439,542,630 $465,104,523 $476,430,971 $487,881,169 $499,773,320 $511,996,156 $524,391,884 $537,085,564 $549,894,608 $563,731,016
Total Load, MWh 1,177,121 2,366,944 3,607,181 3,623,598 3,641,698 3,652,169 3,659,921 3,666,956 3,680,582 3,694,258 3,707,985 3,721,763 3,735,593 3,749,473 3,763,406 3,777,390 3,791,426 3,805,514 3,819,655 3,833,848 3,848,093
Contra Costa CCA Customer Charges, $/MWh (before Reserve Fund Adjustment)
Average Contra Costa CCA generation $72.5 $73.9 $75.2 $78.6 $81.8 $85.5 $88.1 $93.5 $99.7 $107.2 $112.5 $118.1 $124.5 $127.1 $129.6 $132.3 $135.0 $137.8 $140.6 $143.4 $146.5
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $96.2 $93.0 $98.0 $95.1 $98.4 $101.2 $102.7 $106.1 $108.8 $115.2 $119.5 $124.1 $129.6 $130.2 $131.3 $132.9 $135.0 $137.8 $140.6 $143.4 $146.5
PG&E average gen rate for CCA load, $/MWh $101.5 $105.7 $106.6 $112.7 $115.5 $113.8 $113.3 $109.2 $113.2 $119.2 $126.3 $134.2 $144.0 $146.7 $151.0 $155.7 $160.8 $165.0 $170.5 $176.0 $182.5
Reserve Fund Adjustment
Target $12,807,125 $26,233,479 $40,671,027 $42,715,296 $44,691,544 $46,843,714 $48,362,569 $51,411,113 $55,034,215 $59,401,370 $62,556,752 $65,931,394 $69,765,678 $71,464,646 $73,182,175 $74,965,998 $76,799,423 $78,658,783 $80,562,835 $82,484,191 $84,559,652
Reserve Fund Adjustment
Potential Reserve potential $6,234,424 $30,089,033 $31,016,965 $63,518,242 $62,374,145 $46,146,910 $38,989,622 $11,273,777 $16,172,758 $14,983,272 $25,413,827 $37,823,411 $53,680,125 $62,026,869 $74,273,204 $86,296,068 $97,772,267 $103,621,928 $114,307,191 $124,744,938 $138,658,544
Potential Reserve additions $6,234,424 $19,999,055 $14,437,549 $2,044,269 $1,976,248 $2,152,170 $1,518,854 $3,048,544 $3,623,103 $4,367,155 $3,155,381 $3,374,643 $3,834,284 $1,698,967 $1,717,530 $1,783,823 $1,833,425 $1,859,359 $1,904,052 $1,921,357 $2,075,461
Subtractions from reserve fund $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Reserve fund total $6,234,424 $26,233,479 $40,671,027 $42,715,296 $44,691,544 $46,843,714 $48,362,569 $51,411,113 $55,034,215 $59,401,370 $62,556,752 $65,931,394 $69,765,678 $71,464,646 $73,182,175 $74,965,998 $76,799,423 $78,658,783 $80,562,835 $82,484,191 $84,559,652
Contra Costa CCA Customer Charges, $/MWh (with Reserve Fund Adjustment)
Rate adjustment from Reserve Fund $5.3 $8.4 $4.0 $0.6 $0.5 $0.6 $0.4 $0.8 $1.0 $1.2 $0.9 $0.9 $1.0 $0.5 $0.5 $0.5 $0.5 $0.5 $0.5 $0.5 $0.5
Average Contra Costa CCA rate $77.8 $82.3 $79.2 $79.2 $82.4 $86.1 $88.5 $94.3 $100.7 $108.4 $113.3 $119.0 $125.5 $127.5 $130.1 $132.8 $135.5 $138.3 $141.1 $143.9 $147.0
PG&E average exit fees for CCA load $23.7 $19.1 $22.9 $16.6 $16.6 $15.7 $14.6 $12.6 $9.1 $8.0 $7.0 $6.0 $5.1 $3.1 $1.7 $0.6 $0.0 $0.0 $0.0 $0.0 $0.0
Total CCA customer rate $101.5 $101.4 $102.0 $95.7 $98.9 $101.8 $103.1 $106.9 $109.7 $116.3 $120.3 $125.0 $130.6 $130.6 $131.8 $133.4 $135.5 $138.3 $141.1 $143.9 $147.0
Note: Reserve fund revenue is used to reduce CCA rates if (i) CCA rates are lower than PG&E rates or (ii) the reserve fund reaches the ceiling of half a year of expenses.
Contra Costa CCA CO2 emissions
Emissions (Tonnes/MWh)0.04 0.03 0.02 0.02 0.02 0.02 0.02 0.04 0.05 0.05 0.05 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04
Total emissions (Tonnes)48,104 76,449 70,394 71,051 71,298 72,351 73,983 158,002 195,517 194,741 179,036 161,586 144,182 144,830 145,465 146,223 146,793 147,369 147,857 148,803 149,369
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H- 1
Appendix H. MCE and EBCE’s Joint Power
Agreements
209
MARIN CLEAN ENERGY
ADDENDUM NO. 4 TO THE REVISED
COMMUNITY CHOICE AGGREGATION
IMPLEMENTATION PLAN AND
STATEMENT OF INTENT
TO ADDRESS MCE EXPANSION TO THE CITIES
OF AMERICAN CANYON, CALISTOGA,
LAFAYETTE, NAPA, SAINT HELENA, WALNUT
CREEK, AND THE TOWN OF YOUNTVILLE
April 21, 2016
For copies of this document contact Marin Clean Energy in San Rafael, California or visit
www.mcecleanenergy.org
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Table of Contents
CHAPTER 1 – Introduction ............................................................................................................................... 2
CHAPTER 2 – Changes to Address MCE Expansion ........................................................................... 4
Aggregation Process ............................................................................................................................................. 5
Program Phase-In ................................................................................................................................................. 6
Sales Forecast ......................................................................................................................................................... 7
Financial Plan ...................................................................................................................................................... 11
Expansion Addendum Appendices ................................................................................................................. 11
211
CHAPTER 1 – Introduction
The purpose of this document is to make certain revisions to the Marin Clean Energy Implementation
Plan and Statement of Intent in order to address the expansion of Marin Clean Energy (“MCE”) to the
Cities of American Canyon, Calistoga, Lafayette, Napa, Saint Helena, Walnut Creek, and the Town of
Yountville. MCE is a public agency that was formed in December 2008 for purposes of implementing a
community choice aggregation (“CCA”) program and other energy-related programs targeting significant
greenhouse gas emissions (“GHG”) reductions. At that time, the Member Agencies of MCE included
eight of the twelve municipalities located within the geographic boundaries of Marin County: the
cities/towns of Belvedere, Fairfax, Mill Valley, San Anselmo, San Rafael, Sausalito and Tiburon and the
County of Marin (together the “Members” or “Member Agencies”). In anticipation of CCA program
implementation and in compliance with state law, MCE submitted the Marin Energy Authority
Community Choice Aggregation Implementation Plan and Statement of Intent (“Implementation Plan”) to
the California Public Utilities Commission (“CPUC” or “Commission”) on December 9, 2009.
Consistent with its expressed intent, MCE successfully launched its CCA program, Marin Clean Energy
(“MCE” or “Program”), on May 7, 2010 and has been serving customers since that time.
During the second half of 2011, four additional municipalities within Marin County, the cities of Novato
and Larkspur and the towns of Ross and Corte Madera, joined MCE, and a revised Implementation Plan
reflecting updates related to said expansion was filed with the CPUC on December 3, 2011.
Subsequently, the City of Richmond, located in Contra Costa County, joined MCE, and a revised
Implementation Plan reflecting updates related to this expansion was filed with the CPUC on July 6,
2012.
A revision to MCE’s Implementation Plan was then filed with the Commission on November 6, 2012 to
ensure compliance with Commission Decision 12-08-045, which was issued on August 31, 2012. In
Decision 12-08-045, the Commission directed existing CCA programs to file revised Implementation
Plans to conform to the privacy rules in Attachment B of this Decision.
During 2015, the County of Napa and the Cities of Benicia, El Cerrito, and San Pablo joined MCE;
service was extended to customers in unincorporated Napa County during February, 2015 and to
customers in Benicia, El Cerrito and San Pablo during May, 2015. To address the anticipated effects of
these expansions, MCE filed with the Commission a revision to its Implementation Plan on July 18, 2014
to address expansion to the County of Napa (the Commission subsequently certified this revision on
September 15, 2014); following this revision, MCE submitted Addendum #1 to the Revised Community
Choice Aggregation Implementation Plan and Statement of Intent to Address MCE Expansion to the City
of San Pablo (Addendum #1) on September 25, 2014 (the Commission subsequently certified Addendum
#1 on October 29, 2014); and Addendum #2 to the Revised Community Choice Aggregation
Implementation Plan and Statement of Intent to Address MCE Expansion to the City of Benicia
(Addendum #2) on November 21, 2014 (the Commission subsequently certified Addendum #2 on
December 1, 2014); and Addendum #3 to the Revised Community Choice Aggregation Implementation
Plan and Statement of Intent to Address MCE Expansion to the City of El Cerrito (Addendum #3) on
January 8, 2015 (the Commission subsequently certified Addendum #3 on January 16, 2015)
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2 April 2016 – Addendum No. 4
Numerous communities continue to contact MCE regarding membership opportunities, including
specific requests to join MCE and initiate related CCA service within these various jurisdictions.
In response to these inquiries, MCE’s governing board adopted Policy 007, which establishes a
formal process and specific criteria for new member additions. In particular, this policy identifies
several threshold requirements, including the specification that any prospective member
evaluation demonstrate rate-related savings (based on prevailing market prices for requisite
energy products at the time of each analysis) as well as environmental benefits (as measured by
anticipated reductions in greenhouse gas emissions and increased renewable energy sales to CCA
customers) before proceeding with expansion activities, including the filing of related
revisions/addenda to this Implementation Plan. As MCE receives new membership requests, staff
will follow the prescribed evaluative process of Policy 007 and will present related results at
future public meetings. To the extent that membership evaluations demonstrate favorable results
and any new community completes the process of joining MCE, this Implementation Plan will be
revised through a related addendum, highlighting key impacts and consequences associated with
the addition of such new community/communities.
The MCE program now provides electric generation service to approximately 170,000 customers,
including a cross section of residential and commercial accounts. During its more than five-year
operating history, non-member municipalities have monitored MCE progress, evaluating the
potential opportunity for membership, which would enable customer choice with respect to
electric generation service. In response to public interest and MCE’s successful operational track
record, the each of Cities of American Canyon, Calistoga, Lafayette, Napa, Saint Helena, Walnut
Creek and the Town of Yountville requested MCE membership, consistent with MCE Policy 007,
and adopted the requisite ordinance for joining MCE. MCE’s Board of Directors approved the
membership requests at a duly noticed public meeting on April 21, 2016 through the approval of
Resolution No. 2016-01.
This Addendum No. 4 to the Marin Clean Energy Community Choice Aggregation
Implementation Plan and Statement of Intent (“Addendum No. 3”) describes MCE’s expansion
plans to include the Cities of American Canyon, Calistoga, Lafayette, Napa, Saint Helena, Walnut
Creek and the Town of Yountville. According to the Commission, the Energy Division is
required to receive and review a revised MCE implementation plan reflecting
changes/consequences of additional members. With this in mind, MCE has reviewed its revised
Implementation Plan, which was filed with the Commission on July 18, 2014, as well as previous
Addendums, and has identified certain information that requires updating to reflect the changes
and consequences of adding the new municipalities as well as other forecast modifications
reflecting the most recent historical electric energy use within MCE’s existing service territory.
This Addendum No. 4 reflects pertinent changes related to the new member additions as well as
projections that account for MCE’s planned expansion and recent operations. This document
format, including references to MCE’s most recent Implementation Plan revision (filed with the
Commission on July 18, 2014 and certified by the Commission on September 15, 2014), which is
incorporated by reference and attached hereto as Appendix D, addresses all requirements
identified in PU Code Section 366.2(c)(4), including universal access, reliability, equitable
treatment of all customer classes and any requirements established by state law or by the CPUC
concerning aggregated service, while streamlining public review of pertinent changes related to
MCE expansion.
CHAPTER 2 – Changes to Address MCE Expansion to the Cities of American
Canyon, Calistoga, Lafayette, Napa, Walnut Creek, and the Town of Yountville
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3 April 2016 – Addendum No. 4
This Addendum No. 4 addresses the anticipated impacts of MCE’s planned expansion to the
Cities of American Canyon, Calistoga, Lafayette, Napa, Walnut Creek, and the Town of
Yountville, as well as other forecast modifications reflecting the most recent historical electric
energy use within MCE’s existing service territory. As a result of these member additions,
certain assumptions regarding MCE’s future operations have changed, including customer energy
requirements, peak demand, renewable energy purchases, revenues and expenses as well as
various other items. The following section highlights pertinent changes related to this planned
expansion. To the extent that certain details related to membership expansion are not specifically
discussed within this Addendum No. 4, MCE represents that such information shall remain
unchanged relative to the July 18, 2014 Implementation Plan revision, which was certified by the
Commission on September 15, 2014.
With regard to the defined terms Members and Member Agencies, the following communities are
now signatories to the MCE Joint Powers Agreement and represent MCE’s current membership:
Member Agencies
City of American Canyon
City of Belvedere
City of Benicia
City of Calistoga
Town of Corte Madera
City of El Cerrito
Town of Fairfax
City of Lafayette
City of Larkspur
City of Mill Valley
County of Marin
City of Napa
County of Napa
City of Novato
City of Richmond
Town of Ross
Town of San Anselmo
City of San Pablo
City of San Rafael
City of Sausalito
Town of Tiburon
City of Walnut Creek
Town of Yountville
Throughout this document, use of the terms Members and Member Agencies shall now include
the aforementioned communities. To the extent that discussion addresses the process of
aggregation and MCE organization, each of these communities is now an MCE Member and its
electric customers will be offered CCA service consistent with the noted phase-in schedule.
Aggregation Process
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4 April 2016 – Addendum No. 4
MCE’s aggregation process was discussed in Chapter 2 of MCE’s July 18, 2014 Revised
Implementation Plan. This first paragraph of Chapter 2 is replaced in its entirety with the
following verbiage:
As previously noted, MCE successfully launched its CCA Program, MCE, on May 7, 2010 after
meeting applicable statutory requirements and in consideration of planning elements described in
its initial Implementation Plan. At this point in time, MCE plans to expand agency membership
to include the Cities of American Canyon, Calistoga, Lafayette, Napa, Saint Helena, Walnut
Creek and the Town of Yountville. These communities have requested MCE membership, and
MCE’s Board of Directors subsequently approved the membership requests at a duly noticed
public meeting on April 21, 2016.
Program Phase-In
Program phase-in was discussed in Chapter 5 of MCE’s July 18, 2014 Revised Implementation
Plan. Chapter 5 is replaced in its entirety with the following verbiage:
MCE will continue to phase-in the customers of its CCA Program as communicated in this
Implementation Plan. To date, six phases have been successfully implemented, and a seventh
phase will commence in September 2016. The seventh phase will now include service
commencement to customers located within the Cities of American Canyon, Calistoga, Lafayette,
Napa, Saint Helena, Walnut Creek and the Town of Yountville, as reflected in the following
table.
MCE Phase No. Status & Description of Phase Implementation
Date
Phase 1 Complete: MCE Member (municipal)
accounts & a subset of residential,
commercial and/or industrial accounts,
comprising approximately 20 percent of
total customer load within MCE’s original
Member Agencies.
May 7, 2010
Phase 2 Complete: Additional commercial and
residential accounts, comprising
approximately 20 percent of total customer
load within MCE’s original Member
Agencies (incremental addition to Phase 1).
August 2011
Phase 3 Complete: Remaining accounts within
Marin County.
July 2012
Phase 4 Complete: Residential, commercial,
agricultural, and street lighting accounts
within the City of Richmond.
July 2013
Phase 5 Complete: Residential, commercial,
agricultural, and street lighting accounts
within the unincorporated areas of Napa
County, subject to economic and
operational constraints.
February 2015
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5 April 2016 – Addendum No. 4
MCE Phase No. Status & Description of Phase Implementation
Date
Phase 6 Complete: Residential, commercial,
agricultural, and street lighting accounts
within the City of San Pablo, the City of
Benicia and the City of El Cerrito, subject to
economic and operational constraints.
May 2015
Phase 7 September 2016: Residential, commercial,
agricultural, and street lighting accounts
within the Cities of American Canyon,
Calistoga, Lafayette, Napa, Saint Helena,
Walnut Creek and the Town of Yountville,
subject to economic and operational
constraints.
September
2016
This approach has provided MCE with the ability to start slow, addressing any problems or
unforeseen challenges on a small manageable program before gradually building to full program
integration for an expected customer base of approximately 256,000 accounts, following
completion of Phase 7 customer enrollments. This approach has also allowed MCE and its
energy supplier(s) to address all system requirements (billing, collections, payments) under a
phase-in approach to minimize potential exposure to uncertainty and financial risk by “walking”
prior to ultimately “running”. The Board may evaluate other phase-in options based on then-
current market conditions, statutory requirements and regulatory considerations as well as other
factors potentially affecting the integration of additional customer accounts.
Sales Forecast
With regard to MCE’s sales forecast, which is addressed in Chapter 6, Load Forecast and
Resource Plan, MCE assumes that total annual retail sales will increase to approximately 2,800
GWh following Phase 7 expansion. The following tables have also been updated to reflect the
impacts of planned expansion to MCE’s new membership.
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6 April 2016 – Addendum No. 4
Chapter 6, Resource Plan Overview
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Demand (GWh)
Retail Demand -91 -185 -570 -1,110 -1,252 -1,710 -2,103 -2,802 -2,816 -2,830
Distributed Generation 0 2 4 5 9 14 19 24 31 40
Energy Efficiency 0 0 0 0 1 1 22 31 43 58
Losses and UFE -5 -11 -34 -66 -74 -102 -124 -165 -165 -164
Total Demand -97 -195 -601 -1,172 -1,315 -1,796 -2,185 -2,913 -2,906 -2,897
MCE Supply (GWh)
Renewable Resources
Generation 0 0 0 0 0 0 0 0 0 0
Power Purchase Contracts 23 50 289 564 645 927 1,130 1,602 1,695 1,784
Total Renewable Resources 23 50 289 564 645 927 1,130 1,602 1,695 1,784
Conventional Resources
Generation 0 0 0 0 0 0 0 0 0 0
Power Purchase Contracts 74 145 312 608 670 869 1,056 1,310 1,212 1,112
Total Conventional Resources 74 145 312 608 670 869 1,056 1,310 1,212 1,112
Total Supply 97 195 601 1,172 1,315 1,796 2,185 2,913 2,906 2,897
Energy Open Position (GWh)0 0 0 0 0 0 0 0 0 0
2010 to 2019
Marin Clean Energy
Proposed Resource Plan
(GWH)
Chapter 6, Customer Forecast
May-10 Aug-11 Jul-12 Jul-13 Feb-15 May-15 Sep-16
MCE Customers
Residential 7,354 12,503 77,345 106,510 120,204 149,610 225,128
Commercial & Industrial 579 1,114 9,913 13,098 15,316 19,147 27,274
Street Lighting & Traffic 138 141 443 748 1,014 1,219 1,866
Ag & Pumping - <15 113 109 1,467 1,625 1,700
Total 8,071 13,759 87,814 120,465 138,001 171,601 255,968
Marin Clean Energy
Enrolled Retail Service Accounts
Phase-In Period (End of Month)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Customers
Residential 7,354 12,503 77,345 106,510 106,510 149,610 225,128 225,128 226,254 227,385
Commercial & Industrial 579 1,114 9,913 13,098 13,098 19,147 27,274 27,274 27,410 27,547
Street Lighting & Traffic 138 141 443 748 748 1,219 1,866 1,866 1,875 1,885
Ag & Pumping - <15 113 109 109 1,625 1,700 1,700 1,709 1,717
Total 8,071 13,759 87,814 120,465 120,465 171,601 255,968 255,968 257,248 258,534
Marin Clean Energy
Retail Service Accounts (End of Year)
2010 to 2019
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7 April 2016 – Addendum No. 4
Chapter 6, Sales Forecast
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Energy Requirements (GWh)
Retail Demand 91 185 570 1,110 1,252 1,710 2,103 2,802 2,816 2,830
Distributed Generation 0 -2 -4 -5 -9 -14 -19 -24 -31 -40
Energy Efficiency 0 0 0 0 -1 -1 -22 -31 -43 -58
Losses and UFE 5 11 34 66 74 102 124 165 165 164
Total Load Requirement 97 195 601 1,172 1,315 1,796 2,185 2,913 2,906 2,897
2010 to 2019
Marin Clean Energy
Energy Requirements
(GWH)
Chapter 6, Capacity Requirements
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Demand (MW)
Retail Demand 28 46 182 233 234 318 447 499 501 504
Distributed Generation - (1) (2) (3) (5) (8) (11) (14) (18) (23)
Energy Efficiency - - - (0) (0) (0) (5) (7) (10) (13)
Losses and UFE 2 3 11 14 14 19 26 29 28 28
Total Net Peak Demand 30 47 191 244 243 328 457 507 502 496
Reserve Requirement (%)15% 15% 15% 15% 15% 15% 15% 15% 15% 15%
Capacity Reserve Requirement 4 7 29 37 36 49 69 76 75 74
Capacity Requirement Including Reserve 34 55 220 281 279 377 526 583 578 571
2010 to 2019
Marin Clean Energy
Capacity Requirements
(MW)
Chapter 6, Renewable Portfolio Standards Energy Requirements
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Retail Sales 91,219 183,741 566,640 1,105,385 1,240,992 1,694,449 2,061,766 2,747,986 2,741,727 2,732,840
Baseline - 18,244 36,748 113,328 221,077 269,295 394,807 515,442 741,956 795,101
Incremental Procurement Target 18,244 18,504 76,580 107,749 48,218 125,511 120,635 226,515 53,145 52,080
Annual Procurement Target 18,244 36,748 113,328 221,077 269,295 394,807 515,442 741,956 795,101 847,180
% of Current Year Retail Sales 20% 20% 20% 20% 22% 23% 25% 27% 29% 31%
2010 to 2019
Marin Clean Energy
RPS Requirements
(MWH)
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8 April 2016 – Addendum No. 4
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Retail Sales (MWh)91,219 183,741 566,640 1,105,385 1,240,992 1,694,449 2,061,766 2,747,986 2,741,727 2,732,840
Annual RPS Target (Minimum MWh)18,244 36,748 113,328 221,077 269,295 394,807 515,442 741,956 795,101 847,180
Program Target (% of Retail Sales)25% 27% 51% 51% 52% 55% 55% 58% 62% 65%
Program Renewable Target (MWh)22,805 49,610 288,986 563,746 645,316 926,796 1,129,889 1,602,464 1,694,720 1,784,435
Surplus In Excess of RPS (MWh)4,561 12,862 175,658 342,669 376,021 531,989 614,448 860,508 899,619 937,255
Annual Increase (MWh)22,805 26,805 239,376 274,760 81,569 281,480 203,094 472,575 92,256 89,715
2010 to 2019
Marin Clean Energy
RPS Requirements and Program Renewable Energy Targets
(MWH)
Chapter 6, Energy Efficiency
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Retail Demand 91 185 570 1,110 1,252 1,710 2,103 2,802 2,816 2,830
MCE Energy Efficiency Goal 0 0 0 0 -1 -1 -22 -31 -43 -58
Energy Efficiency Savings Goals
(GWH)
2010 to 2019
Marin Clean Energy
Chapter 6, Demand Response
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Total Capacity Requirement (MW)34 55 220 281 279 377 526 583 578 571
Greater Bay Area Capacity Requirement (MW)5 9 35 44 44 40 56 62 61 61
Demand Response Target - - - - - - - 7 14 29
Percentage of Local Capacity Requirment 0% 0% 0% 0% 0% 0% 0% 12% 23% 47%
Marin Clean Energy
Demand Response Goals
(MW)
2010 to 2019
Chapter 6, Distributed Generation
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
DG Capacity - 1 2 3 5 8 11 14 18 23
Marin Clean Energy
Distributed Generation Projections
(MW)
to
219
Financial Plan
With regard to MCE’s financial plan, which is addressed in Chapter 7, Financial Plan, MCE has updated
its expected operating results, which now include projected impacts related to service expansion within
MCE’s new member communities. The following table reflects updated operating projections in
consideration of these planned expansions.
Chapter 7, CCA Program Implementation Feasibility Analysis
Expansion Addendum Appendices
Appendix A: Marin Clean Energy Resolution 2016-01
Appendix B: Joint Powers Agreement
Appendix C: Member Ordinances
Appendix D: Marin Clean Energy Revised Implementation Plan and Statement of Intent (July 18,
2014)
CATEGORY 2013 2014 2015 2016 2017 2018 2019 2020 2021
I. REVENUES FROM OPERATIONS ($)
ELECTRIC SALES REVENUE 79,097,747 96,963,884 135,021,092 169,271,724 216,452,212 213,543,823 214,611,542 220,764,561 228,524,436
LESS UNCOLLECTIBLE ACCOUNTS (395,489) (484,819) (675,105) (846,359) (1,082,261) (1,067,719) (1,073,058) (1,103,823) (1,142,622)
LESS NET ENERGY METERING CREDITS (314,809) (385,916) (546,879) (362,202) (425,212) (427,338) (429,475) (431,621) (433,781)
TOTAL REVENUES 78,702,259 96,479,065 134,345,986 168,425,365 215,369,951 212,476,104 213,538,484 219,660,739 227,381,813
II. COST OF OPERATIONS ($)
(A) ADMINISTRATIVE AND GENERAL (A&G)
STAFFING 1,386,303 1,825,000 2,710,500 4,598,125 5,485,201 5,649,757 5,819,250 5,993,828 6,173,642
CONTRACT SERVICES 4,457,964 4,572,751 4,838,757 6,351,549 7,383,653 7,477,211 7,572,972 7,670,983 7,771,338
IOU FEES (INCLUDING BILLING)584,729 660,114 877,953 1,101,770 1,444,734 1,495,516 1,548,084 1,602,499 1,658,827
OTHER A&G 302,806 373,125 610,500 519,624 472,850 486,017 499,579 513,549 527,937
SUBTOTAL A&G 6,731,802 7,430,990 9,037,711 12,571,067 14,786,438 15,108,502 15,439,885 15,780,858 16,131,744
(B) COST OF ENERGY 67,886,604 82,928,413 115,624,967 142,856,566 183,655,605 166,704,670 175,122,240 182,541,059 190,601,655
(C) DEBT SERVICE 1,195,162 1,195,162 2,450,457 455,000 455,000 455,000 455,000 455,000 455,000
TOTAL COST OF OPERATION 75,813,568 91,554,564 127,113,135 155,882,633 198,897,043 182,268,172 191,017,125 198,776,917 207,188,399
CCA PROGRAM SURPLUS/(DEFICIT)2,888,691 4,924,500 7,232,851 12,542,733 16,472,908 30,207,932 22,521,359 20,883,822 20,193,415
Marin Clean Energy
Summary of CCA Program Phase-In
(January 2013 through December 2021)
220
APPENDIX A
221
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10 April 2016 – Addendum No. 4
APPENDIX B
Marin Energy Authority
- Joint Powers Agreement -
Effective December 19, 2008
As amended by Amendment No. 1 dated December 3, 2009
As further amended by Amendment No. 2 dated March 4, 2010
As further amended by Amendment No. 3 dated May 6, 2010
As further amended by Amendment No. 4 dated December 1, 2011
As further amended by Amendment No. 5 dated July 5, 2012
As further amended by Amendment No. 6 dated September 5, 2013
As further amended by Amendment No. 7 dated December 5, 2013
As further amended by Amendment No. 8 dated September 4, 2014
As further amended by Amendment No. 9 dated December 4, 2014
As further amended by Amendment No. 10 dated April 21, 2016
Among The Following Parties:
City of American Canyon
City of Belvedere
City of Benicia
City of Calistoga
Town of Corte Madera
City of El Cerrito
Town of Fairfax
City of Lafayette
City of Larkspur
City of Mill Valley
City of Napa
City of Novato
City of Richmond
Town of Ross
Town of San Anselmo
City of San Pablo
City of San Rafael
City of Sausalito
City of St. Helena
Town of Tiburon
City of Walnut Creek
Town of Yountville
County of Marin
County of Napa
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11 April 2016 – Addendum No. 4
MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT
This Joint Powers Agreement (“Agreement”), effective as of December 19,
2008, 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. In 2006, the State Legislature adopted AB 32, the Global Warming Solutions Act,
which mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels.
The California Air Resources Board is promulgating regulations to implement AB
32 which will require local government to develop programs to reduce
greenhouse emissions.
3. 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.
4. The Parties desire to establish a separate public agency, known as the Marin
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.
5. The Initial Participants have each adopted an ordinance electing to implement
through the Authority Community Choice Aggregation, an electric service
enterprise agency available to cities and counties 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. Regardless of whether or not Program Agreement 1 is approved and the
CCA Program becomes operational, the parties intend for the Authority to
continue to study, promote, develop, conduct, operate and manage other energy
programs.
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12 April 2016 – Addendum No. 4
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
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 MARIN ENERGY AUTHORITY
2.1 Effective Date and Term. This Agreement shall become effective and Marin
Energy Authority shall exist as a separate public agency on the date this
Agreement is executed by at least two Initial Participants after the adoption of the
ordinances required by Public Utilities Code Section 366.2(c)(10). 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. During the first 180 days after the Effective Date, 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)(10) 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 and is not an
Initial Participant and (ii) to Initial Participants that have not executed and
delivered this Agreement within the time period described above.
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13 April 2016 – Addendum No. 4
2.3 Formation. There is formed as of the Effective Date a public agency named the
Marin 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 board of each
Party.
2.4 Purpose. The purpose of this Agreement is to establish an independent public
agency in order to exercise powers common to each Party 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, as further
described in Section 5.1. The Parties intend that subsequent agreements shall
define the terms and conditions associated with the actual implementation of the
CCA Program and any other energy programs approved by the Authority.
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 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;
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
aids from any federal, state or local public agency;
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14 April 2016 – Addendum No. 4
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 agreements relating to the provision of
services 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 County of Marin.
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 such county requesting that the incorporated municipality or
county, as the case may be, become a member of the Authority, (b) the adoption,
by an affirmative vote of the Board satisfying the requirements described in
Section 4.9.1, 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)(10)
and execution of this Agreement and other necessary program agreements by the
incorporated municipality or county, (d) payment of the membership payment, if
any, and (e) satisfaction of any conditions established by the Board.
Notwithstanding the foregoing, in the event the Authority decides to not
implement a CCA Program, the requirement that an additional party adopt the
ordinance required by Public Utilities Code Section 366.2(c)(10) shall not apply.
Under such circumstance, the Board resolution authorizing membership of an
additional incorporated municipality or county shall be adopted in accordance
with the voting requirements of Section 4.10.
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15 April 2016 – Addendum No. 4
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. 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 or the alternate Director shall be a member of the governing body
of the Party.
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 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 shall constitute a quorum, except that less
than a quorum may adjourn from time to time in accordance with law.
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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 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 Related to the CCA Program.
4.9.1. To be effective, on all matters specifically related to the CCA Program, a
vote of the Board shall consist of the following: (1) a majority of all
Directors shall vote in the affirmative or such higher voting percentage
expressly set forth in Sections 7.2 and 8.4 (the “percentage vote”) and (2)
the corresponding voting shares (as described in Section 4.9.2 and Exhibit
D) of all such Directors voting in the affirmative shall exceed 50%, or
such other higher voting shares percentage expressly set forth in Sections
7.2 and 8.4 (the “percentage voting shares”), provided that, in instances in
which such other higher voting share percentage would result in any one
Director having 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.
4.9.2. Unless otherwise stated herein, voting shares of the Directors shall be
determined by combining the following: (1) an equal voting share for each
Director determined in accordance with the formula detailed in Section
4.9.2.1, below; and (2) an additional voting share determined in
accordance with the formula detailed in Section 4.9.2.2, below.
4.9.2.1 Pro Rata Voting Share. Each Director shall have an equal voting
share as determined by the following formula: (1/total number of
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Directors) multiplied by 50, and
4.9.2.2 Annual Energy Use Voting Share. Each Director shall have an
additional voting share as determined by the following formula:
(Annual Energy Use/Total Annual Energy) multiplied by 50, where
(a) “Annual Energy Use” means, (i) with respect to the first 5 years
following the Effective Date, the annual electricity usage, expressed
in kilowatt hours (“kWhs”), within the Party’s respective jurisdiction
and (ii) with respect to the period after the fifth anniversary of the
Effective Date, the annual electricity usage, expressed in kWhs, 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 shall be adjusted annually as
soon as reasonably practicable after January 1, but no later than
March 1 of each year
4.9.2.3 The voting shares are set forth in Exhibit D. Exhibit D may be
updated to reflect revised annual energy use amounts and any
changes in the parties to the Agreement without amending the
Agreement provided that the Board is provided a copy of the updated
Exhibit D.
4.10 Board Voting on General Administrative Matters and Programs Not
Involving CCA. Except as otherwise provided by this Agreement or the
Operating Rules and Regulations, each member shall have one vote on general
administrative matters, including but not limited to the adoption and amendment
of the Operating Rules and Regulations, and energy programs not involving CCA.
Action on these items shall be determined by a majority vote of the quorum
present and voting on the item or such higher voting percentage expressly set
forth in Sections 7.2 and 8.4.
4.11 Board Voting on CCA Programs Not Involving CCA That Require Financial
Contributions. The approval of any program or other activity not involving
CCA that requires financial contributions by individual Parties shall be approved
only by a majority vote of the full membership of the Board subject to the right of
any Party who votes against the program or activity to opt-out of such program or
activity pursuant to this section. The Board shall provide at least 45 days prior
written notice to each Party before it considers the program or activity for
adoption at a Board meeting. Such notice shall be provided to the governing body
and the chief administrative officer, city manager or town manager of each Party.
The Board also shall provide written notice of such program or activity adoption
to the above-described officials of each Party within 5 days after the Board adopts
the program or activity. Any Party voting against the approval of a program or
other activity of the Authority requiring financial contributions by individual
Parties may elect to opt-out of participation in such program or activity by
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providing written notice of this election to the Board within 30 days after the
program or activity is approved by the Board. Upon timely exercising its opt-out
election, a Party shall not have any financial obligation or any liability whatsoever
for the conduct or operation of such program or activity.
4.12 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.).
4.13 Selection of Board Officers.
4.13.1 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 form the Authority pursuant to the provisions of this
Agreement.
4.13.2 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.
4.13.3 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
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
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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.
4.14 Administrative Services Provider. The Board may appoint one or more
administrative services providers to serve as the Authority’s agent for planning,
implementing, operating and administering the CCA Program, and any other
program approved by the Board, in accordance with the provisions of a written
agreement between the Authority and the appointed administrative services
provider or providers that will be known as an Administrative Services
Agreement. The Administrative Services Agreement shall set forth the terms and
conditions by which the appointed administrative services provider shall perform
or cause to be performed all tasks necessary for planning, implementing,
operating and administering the CCA Program and other approved programs. The
Administrative Services Agreement shall set forth the term of the Agreement and
the circumstances under which the Administrative Services Agreement may be
terminated by the Authority. This section shall not in any way be construed to
limit the discretion of the Authority to hire its own employees to administer the
CCA Program or any other program.
ARTICLE 5
IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS
5.1 Preliminary Implementation of the CCA Program.
5.1.1 Enabling Ordinance. Except as otherwise provided by Section 3.1, prior
to the execution of this Agreement, each Party shall adopt an ordinance in
accordance with Public Utilities Code Section 366.2(c)(10) 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.
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5.1.3 Effect of Vote On Required Implementation Action. In the event that
two or more Parties vote to approve Program Agreement 1 or any earlier
action required for the implementation of the CCA Program (“Required
Implementation Action”), but such vote is insufficient to approve the
Required Implementation Action under Section 4.9, the following will
occur:
5.1.3.1 The Parties voting against the Required Implementation
Action shall no longer be a Party to this Agreement and
this Agreement shall be terminated, without further notice,
with respect to each of the Parties voting against the
Required Implementation Action at the time this vote is
final. The Board may take a provisional vote on a
Required Implementation Action in order to initially
determine the position of the Parties on the Required
Implementation Action. A vote, specifically stated in the
record of the Board meeting to be a provisional vote, shall
not be considered a final vote with the consequences
stated above. A Party who is terminated from this
Agreement pursuant to this section shall be considered the
same as a Party that voluntarily withdrew from the
Agreement under Section 7.1.1.1.
5.1.3.2 After the termination of any Parties pursuant to Section
5.1.3.1, the remaining Parties to this Agreement shall be
only the Parties who voted in favor of the Required
Implementation Action.
5.1.4 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, 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 County Funding of Initial Costs. The County of Marin shall fund the
Initial Costs of the Authority in implementing the CCA Program in an
amount not to exceed $500,000 unless a larger amount of funding is
approved by the Board of Supervisors of the County. This funding shall
be paid by the County at the times and in the amounts required by the
Authority. In the event that the CCA Program becomes operational, these
Initial Costs paid by the County of Marin shall be included in the customer
charges for electric services as provided by Section 6.3.4 to the extent
permitted by law, and the County of Marin shall be reimbursed from the
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payment of such charges by customers of the Authority. The Authority
may establish a reasonable time period over which such costs are
recovered. In the event that the CCA Program does not become
operational, the County of Marin shall not be entitled to any
reimbursement of the Initial Costs it has 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 services under the CCA
Program, including the establishment and maintenance of various reserve
and performance funds, shall be recovered through charges to CCA
customers receiving such electric services.
6.3.4 General Costs. Costs that are not directly or indirectly attributable to the
provision of electric services under the CCA Program, as determined by
the Board, shall be defined as general costs. General costs shall be shared
among the Parties on such basis as the Board shall determine pursuant to
an Authority Document.
6.3.5 Other Energy Program Costs. Costs that are directly or indirectly
attributable to energy programs approved by the Authority other than the
CCA Program shall be shared among the Parties on such basis as the
Board shall determine pursuant to an Authority Document.
ARTICLE 7
WITHDRAWAL AND TERMINATION
7.1 Withdrawal.
7.1.1 General.
7.1.1.1 Prior to the Authority’s execution of Program Agreement 1, any
Party may withdraw its membership in the Authority by giving no
less than 30 days advance written notice of its election to do so,
which notice shall be given to the Authority and each Party. To
permit consideration by the governing body of each Party, the
Authority shall provide a copy of the proposed Program Agreement
1 to each Party at least 90 days prior to the consideration of such
agreement by the Board.
7.1.1.2 Subsequent to the Authority’s execution of Program Agreement 1, 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 6
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months advance written notice of its election to do so, which notice
shall be given to the Authority and each Party, and upon such other
conditions as may be prescribed in Program Agreement 1.
7.1.2 Amendment. Notwithstanding Section 7.1.1, a Party may withdraw its
membership in the Authority following an amendment to this Agreement
in the manner provided by Section 8.4.
7.1.3 Continuing Liability; Further Assurances. A Party that withdraws its
membership in the Authority may be subject to certain continuing
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 an affirmative vote of the Board in which the
minimum percentage vote and percentage voting shares, as described in Section
4.9.1, shall be no less than 67%, excluding 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 continuing liabilities, as described in Section
7.3. In the event that the Authority decides to not implement the CCA Program,
the minimum percentage vote of 67% shall be conducted in accordance with
Section 4.10 rather than Section 4.9.1.
7.3 Continuing Liability; Refund. Upon a withdrawal or involuntary termination of
a Party, 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, it being agreed that the Party shall
not be responsible for any claims, demands, damages, or liabilities arising after
the date of the Party’s withdrawal or involuntary termination. In addition, such
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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 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.
7.5 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 program
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. Should
such efforts to settle a dispute, after reasonable efforts, fail, the dispute shall be
settled by binding arbitration in accordance with policies and procedures
established by the Board.
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 seq. Nothing in this section shall be construed to limit the defenses
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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 is necessary to protect the interests of the Authority, the Parties and the public.
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 by an
affirmative vote of the Board in which the minimum percentage vote and
percentage voting shares, as described in Section 4.9.1, shall be no less than 67%.
The Authority shall provide written notice to all Parties of amendments to this
Agreement, including the effective date of such amendments. A Party shall be
deemed to have withdrawn its membership in the Authority effective immediately
upon the vote of the Board approving 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.
As described in Section 7.3, a Party that withdraws its membership in the
Authority in accordance with the above-described procedure may be subject to
continuing liabilities incurred prior to the Party’s withdrawal. In the event that
the Authority decides to not implement the CCA Program, the minimum
percentage vote of 67% shall be conducted in accordance with Section 4.10 rather
than Section 4.9.1.
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.
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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 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 48
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. Notices given to one Party
shall be copied to all other Parties. Notices given to the Authority shall be copied
to all Parties.
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APPENDIX C
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265
CITY OF BELVEDERE
ORDINANCE NO.2OO8.5
AÀI ORDINA¡ICE OF TIIE CITY COTJNCIL OF TIIE CITY OF BELVEDERE
APPROVING TIIE MARIN EATERGY AUTIIORITY JOINT POWERS
AGREEMENT AIYD AUTHORIZING TITE IMPLEMENTATION OF'
A COMMI,J]\IITY CHOICE AGGREGATION PROGRAM
TIIE CITY COTJNCIL OF TIIE CITY OF BELVEDERE DOES ORDAIN AS
FOLLOWS:
SECTION f. The City of Belvedere has been actively investigating options to provide electric
services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill I l7 (Stat.
2002, ch. 838; see Califomia Public Utiiities Code section366.2; hereinafter referred to as the
"Act'), which authorizes any Califomià city or county, whose governing body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice Aggregation
(CCA) program through a joint powers agency, and to this end the City has been participating
since 2003 in the evaluation of a CCA program for the County of Marin and the cities and towns
within it.
SECTION 4. On lune 22, 2006, the City joined a Local Government Task Force (LG'|F),
which was comprised of elected officials and representatives of the County of Marin and each
municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin communities and customers. The LGTF had f,rve meetings with
the frnal meeting taking place on March 6, 2008. The LGTF meetings looked at issues
including:
A.
B.
The costs, benefits and risks of a CCA including legal liability issues.
The governance and business planning of a CCA.
The feasibility of a CCA and deciding whether to pursue formation of a countywide CCA
organization.
Public education.
C.
D.
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Ordinance No. 2008-5
City of Belvedere
Page2
SECTION 5. Through Docket No. R.03-10-003, the Califomia Public Utilities Commission has
issued various decisions and rulings addressing the implementation of Community Choice
Aggregation programs, including the recent issuance of a procedure by which the California
Public Utilities Commission will review "Implementation Plans," which are required for
submittal under the Act as the means of describing the Community Choice Aggregation program
and assuring compliance with various elements contained in the Act.
SECTION 6. Representatives from the City along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement")
(attached hereto as Exhibit A) in order to accomplish the following:
A.
B.
energy
Choice
To fbrm a Joinl Powers Authority (JPA) known as "Marin Energy."
To specify the terms and conditions by which participants may participate as a group in
programs, including but not limited to the preliminary implementation of a Community
Aggregation program.
SECTION 7. Representatives from the
Business Plan (attached hereto as Exhibit
and the Community Choice Aggregation
Energy Authority.
City along with the LGTF members have developed a
B) that describes the formation of Marin Clean Energy
program to be implemented by and through the Marin
A.
B.
SECTION 8. A final Implementation Plan will be submitted for revierv and adoption by the
Board of Directors of the Marin Energy Authority as soon after the formation of the Authority as
reasonabl y practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
To provide greater levels of local involvement in and collaboration on energy decisions.
To increase significantly the amount of renewable energy available to Marin customers.
C. To provide initial price stability, long-term electricity cost savings and other benefits for
the community.
D. To reduce green house gases that are emitted by creating electricity fbr the community.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
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Ordinance No. 2008-5
City of Belvedere
Page 3
SECTION ff. The Joint Powers Agreement expressly allows the City to withdraw its
membership in the Marin Energy Authority (and its participation in the Community Choice
Aggregation program) prior to the actual implementation of a Comrnunity Choice Aggregation
program through Program Agreement L
SECTION 12. A city, town or county may not participate in the Marin Energy Joint Powers
Authority without also participating in the Community Choice Aggregation program unless the
Board of Directors of the Marin Energy Joint Powers Authority decides to not implement or
operate a Community Choice Aggregation program after the Authority is established.
SECTION 13. Based upon all of-the above, the Council approves the Joint Powers Agreement
attached hereto as Exhibit A and elects to implement a Cornmunity Choice Aggregation program
within the City's jurisdiction by and through the City's participation in the Marin Energy
Authority, as described in the Business Plan in substantially the form attached hereto as Exhibit
B, and subject to the City's right to forego the actual implementation of a Community Choice
Aggregation program pursuant to specifred withdrawal rights described in the Joint Powers
Agreement. The Mayoi is hereby authorized to execute the attached Joint Powers Agreement.
SECTION 14. This ordinance shall take effèct and be in force thirty (30) days after the date of
its passage. Wilhin fìfteen (15) days following its passage, a summary of the ordinance shall be
published with the names of those city councilmembers voting for and against the ordinance and
the city clerk shall post in the office of the city clerk a certified copy of the full text of the
adopted ordinance along with the names of the members voting for and against the ordinance.
INTRODUCED AT A PUBLIC HEARING on November 10, 2008, and adopted at a regular
meeting of the Belvedere City Council on December 8,2008, by the following vote:
AYES:
NOES:
ABSENT:
ABSTAIN:
Gerald
None
Barbara Morrison
None I
Butler, Sandra Donnell, John C. Telischak, and Mayor Thomas Cromwell
APPRO
Thomas Cromwell, Mayor
ie Carpentiers,y City Clerk
268
Appendix D269
Appendix D270
271
272
273
274
275
276
277
ORDINANCE NO. 739
AN ORDINANCE OF THE TOWN COTINCIL OF THE TOWN OF FAIRFAX APPROVING
THE MARIN ENERGY AUTHOzuTY JOINT POWERS AGREEMENT AND AUTHORIZING
THE IMPLEMENTATION OF A COMMLTNITY CHOICE AGGREGATION
PROGRAM
The Town Councilof the Town of Fairfax ordains as follows:
SECTION L The Town of Fairfax has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill I 17
(Stat. 2002, ch. 838; see California Public Utilities Code section 366.2: hereinafter referred to as
the "Act"), which authorizes any California city or county, whose governing body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Communify Choice Aggregation
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the Town has been
participating since 2003 in the evaluation of a CCA program for the County of Marin and the cities
and towns within it.
SECTION 4. On June22,2006, the Town joined a Local Government Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin and
each municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin communities and customers. The LGTF had frve meetings with
the final meeting taking place on March 6, 2008. The LGTF meetings looked at issues including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of Communify
Choice Aggregation programs, including the recent issuance of a procedure by which the
California Public Utilities Commission will review "Implementation Plans," which are required for
submittal under the Act as the means of describing the Community Choice Aggregation program
and assuring compliance with various elements contained in the Act.
SECTION 6. Representatives from the Town along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement',)
(attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authorify (JpA) known as ,,Marin Energy" and
Item 8(b) Ord 739.DOC l-
278
(b) To speci$ the terms and conditions by which participants may participate as a
group in energy programs, including but not limited to the preliminary implementation of a
Community Choice Aggregation program.
SECTION 7, Representatives from the Town along with the LGTF members have
developed a Business PIan (attached hereto as Exhibit B that describes the formation of Marin
Clean Energy and the Communiry Choice Aggregation program to be implemented by and through
the Marin Energy Authority.
SECTION L A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the Authority
as reasonably practicable.
SECTION 9. As desuibed in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish all
of the following:
(a) To provide greater levels of localinvolvement in and collaboration on energy
decisions,
(b) To increase significantly the amount of renewable energy available to Marin
customers,
(c) To provide initial price stability, long-term electricity cost savings and other
benefits for the community, and
(d) To reduce green house gases that are emitted by creating electricity for the
communify.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION I l. The Joint Powers Agreement expressly allows the Town to withdraw its
membership in the Marin Enerry Authorify (and its participation in the Community Choice
Aggregation program) prior to the actual implementation of a Community Choice Aggregation
program through Program Agreement L
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program unless
the Board of Directors of the Marin Energy Joint Powers Authority decides to not implement or
operâte a Community Choice Aggregation program after the Authority is established.
SECTION 13. Based upon all of the above, the Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice Aggregation
program within the Town's jurisdiction by and through the Town's participation in the Marin
Energy Authority, as described in the Business Plan in substantially the form attached hereto as
Exhibit B, and subject to the Town's right to forego the actual implementation of a Community
Choice Aggregation program pursuant to specified withdrawal rights described in the Joint Powers
Agreement. The Mayor is hereby authorized to execute the attached Joint Powers Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption.
Item 8(b) Ord 739.DOC -2-
279
Copies of the foregoing ordinance shall, within fifteen (15) days after its final passage and
adoption, be posted in three public places in the Town of Fairfax, to wit: Bulleting Board, Fairfax
Town Offices, Town Hall; Bulletin Board, Fairfax Post Office; and Bulletin Board, Fairfax
Women's Club Building, which said places are hereby designated for that purpose.
The foregoing ordinance was duly and regularly introduced at a regular meeting of the
Town Council of the Town of Fairfax held in said town on the 5"'day of November, 2008, and
thereafter adopted on the 19th day of November, 2008 by the following vote, to wit:
AYES:
NOES:
ABSENT:
The foregolngdoctment ls a or¡ct
copy of the orlglnal on reod
Bragman, Brandborg, Maggiore, Tremaine
None
Weinsoff
!,
MAGGIO
Aftest:
Item 8(b) Ord 739.DOC -3-
280
281
282
283
284
ORDINANCE NO. I.237
AN ORDINANCE OF THE CITY COUNCIL
OF THB CITY OF MILL VALLEY APPROVING THB
MARIN ENERGY AUTHORITY JOINT POWERS AGREEMENT
AND AUTHORIZING THE IMPLEMENTATION OF
A COMMI.INITY CHOICE AGGREGATION PROGRAM
The City Council of the City of Mill Valley ordains as follows:
SECTION 1. The City of Mill Valley has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill I 17
(Stat. 2002, ch. 838; see California Public Utilities Code section366.2; hereinafter referred to as
the "Act"), which authorizes any California city or county, whose governing body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agençy, and to this end the City has been
participating since 2003 in the evaluation of a CCA program for the County of Marin and the
cities and towns within it.
SECTION 4. On June 22, 2006, the City joined a Local Government Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin and
each municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin communities and customers. The LGTF had five meetings with
the final meeting taking place on March 6,2008, The LGTF meetings looked at issues including:
(a) The costs, benefi.ts and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No, R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
Community Choice Aggregation programs, including the recent issuance of a procedure by which
the California Public Utilities Commission will review "Implementation Plans," which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act,
285
SECTION 6. Representatives from the City along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement")
(attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy" and
(b) To specify the terms and conditions by which participants may participate as a group
in energy programs, including but not limited to the preliminary implementation of a
Community Choice Aggregation prcgram.
SECTION 7. Representatives from the City along with the LGTF members have
developed a Business Plan (attached hereto as Exhibit B that describes the formation of Marin
Clean Energy and the Community Choice Aggregation program to be implemented by and
through the Marin Energy Authority).
SECTION 8. A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the Authority
as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
(a) To provide greater levels of local involvement in and collaboration on energy
decisions.
(b) To increase significantly the amount of renewable energy available to Marin
customers,
(c) To provide initial price stability, long - term electricity cost savings and other benefits
for the community, and
(d) To reduce green house gases
community.
that are emitted by creating electricity for the
SECTION 10, The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION I L The Joint Powers Agreement expressly allows the City to withdraw its
membership in the Marin Energy Authority (and its participation in the Community Choice
Aggregation program) prior to the actual implementation of a Community Choice Aggregation
program through Program Agreement l,
286
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation progrcm
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
implement or operate a Community Choice Aggregation program after the Authority is
established.
SECTION 13. Based upon all of the above, the Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice
Aggregation program within the City's jurisdiction by and through the City's participation in the
Marin Energy Authority, as described in the Business Plan in substantially the form attached
hereto as Exhibit B, and subject to the City's right to forego the actual implementation of a
Community Choice Aggregation program pursuant to specified withdrawal rights described in the
Joint Powers Agreement. The Mayor is hereby authorized to execute the attached Joint Powers
Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption,
and, before the expiration of 30 days after its passage, a summary of this ordinance shall be
published once with the names of the members of the Council voting for and against the same in
the Marin lndependent Journal, a newspaper of general circulation published in the County of
Marin.
THE FOREGOING ORDINANCE was first read at a regular meeting of the Mill Valley City
Council on 17tr'day of November, 2008, and adopted at a regular meeting of the Mill Valley City
Council on 1't day of December, 2008, by the following vote:
AYES: Councilmember Beman, Lion, Wachtel and Mayor Marshall
NOES: None
ABSTAIN: CouncilmemberMoulton-Peters
ABSENT: None
Marshall,
Kimberly Wilson,y City Clerk
287
ORDINANCE 02016-3
ORDINANCE OF THE CITY COUNCIL OF THE CITY OF
NAPA, STATE OF CALIFORNIA, APPROVING THE MARIN
CLEAN ENERGY JOINT POWERS AGREEMENT AND
AUTHORIZING THE IMPLEMENTATION OF A
COMMUNITY CHOICE AGGREGATION PROGRAM
WHEREAS, the City of Napa has been actively investigating options to provide
electric services to constituents within its service area with the intent of promoting use of
renewable energy and reducing energy related greenhouse gas emissions; and
WHEREAS, on September 24, 2002, the Governor signed into law Assembly Bill
117 (Stat. 2002, ch. 838; see California Public Utilities Code section 366.2; hereinafter
referred to as the "Act"), which authorizes any California city or county, whose governing
body so elects, to combine the electricity load of its residents and businesses in a
community-wide electricity aggregation program known as Community Choice
Aggregation; and
WHEREAS, the Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and on December 19, 2008,
the Mahn Clean Energy (MCE) was established as a joint power authority pursuant to a
Joint Powers Agreement, as amended from time to time; and
WHEREAS, on February 2, 2010, the California Public Utilities Commission
certified the "Implementation Plan" of the MCE, confirming the MCE's compliance with the
requirements of the Act; and
WHEREAS, in order to become a member of the MCE, the Act requires the City of
Napa to individually adopt an ordinance electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the MCE;
and
WHEREAS, the City Council has considered all information related to this matter,
as presented at the public meeting of the City Council identified herein, including any
supporting reports by City Staff, and any information provided during public meetings.
NOW, THEREFORE, BE IT ORDAINED, by the City Council of the City of Napa as
follows:
SECTION 1: Based upon all of the above, the City Council elects to implement a
Community Choice Aggregation program within the City of Napa's jurisdiction by and
through the City of Napa's participation in Mahn Clean Energy. The City Manager is
hereby authorized to execute the MCE Joint Powers Agreement.
SECTION 2: Severabilitv. If any section, sub-section, subdivision, paragraph,
clause or phrase in this Ordinance, or any part thereof, is for any reason held to be invalid
02016-3 Page 1 of 2 February 2, 2016 288
or unconstitutional, such decision shall not affect the validity of the remaining sections or
portions of this Ordinance or any part thereof. The City Council hereby declares that it
would have passed each section, sub-section, subdivision, paragraph, sentence, clause
or phrase of this Ordinance, irrespective of the fact that any one or more sections, sub-
sections, subdivisions, paragraphs, sentences, clauses or phrases may be declared
invalid or unconstitutional.
SECTION 3: Effective Date. This Ordinance shall become effective on the later of
(a) the date the Board of Directors of MCE adopts a Resolution adding the City of Napa
as a member of MCE, or (b) 30 days after the adoption of this ordinance.
City of Napa, a municipal corporation
MAYOR :c., (SUS
ATTEST:
CLER OF E. THE 1;41-Y624UPA
LiBIS sa :Inca.
STATE OF CALIFORNIA
COUNTY OF NAPA 1- SS:
CITY OF NAPA
I, Dorothy Roberts, City Clerk of the City of Napa,
foregoing Ordinance had its first reading and was introduced
of the City Council on the 19 th day of January, 2016, and had
adopted and passed during the regular meeting of the City
February, 2016, by the following vote:
do hereby certify that the
during the regular meeting
its second reading and was
Council on the 2nd day of
AYES: Inman, Luros, Mott. Sedgley, Techel
NOES: None
ABSENT: None
ABSTAIN: None
ATTEST:
Approved as to Form:
Michael W. Barrett
City Attorney
LILL Jilibulalanon,tion_ Defiecuutvty ity Clot
Dorothy Roberts
City Clerk
02016-3
Page 2 of 2 February 2, 2016 289
290
291
292
293
TO\ryN OF ROSS
ORDINANCE NO. 612
ORDINANCE OF THE TOWN COUNCIL OF THE TO\ryN OF
ROSS APPROVING THE MARIN ENERGY AUTHORITY JOINT POWERS
AGREEMENT AND AUTHORIZING THE IMPLEMENTATION OF A
COMMUNITY CHOICE AGGREGATION PROGRAM
The Town Council of the Town of Ross ordains as follows:
SECTION 1. The Town of Ross has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
enefgy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill 117
(Stat.2002, ch. 838; see California Public Utilities Code section 366.2; hereinafter referred to as
the "Act"), which authorizes any California city or county, whose goveming body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the Town has been
participating since 2003 inthe evaluation of a CCA program for the County of Marin and the
cities and towns within it.
SECTION 4. On June22,2006, the Town joined a Local Government Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin
and each municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin communities and customers. The LGTF had five meetings with
the final meeting taking place on March 6,2008. The LGTF meetings looked at issues
including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
Community Choice Aggregation programs, including the recent issuance of a procedure by
294
which the California Public Utilities Commission will review o'Implementation Plans," which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act.
SECTION 6. Representatives from the Town along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement")
(attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy" and
(b) To specify the terms and conditions by which participants may participate as
a group in energy programs, including but not limited to the preliminary implementation
of a Community Choice Aggregation program.
SECTION 7. Representatives from the Town along with the LGTF members have
developed a Business Plan (attached hereto as Exhibit B that describes the formation of Marin
Clean Energy and the Community Choice Aggregation program to be implemented by and
through the Marin Energy Authority.
SECTION 8. A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the
Authority as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
(a) To provide greater levels of local involvement in and collaboration on energy
decisions,
(b) To increase significantly the amount of renewable energy available to Marin
customers,
(c) To provide initial price stability, long - term electricity cost savings and other
benefits for the community, and
(d) To reduce green house gases that are emitted by creating electricity for the
communitv.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION 11. The Joint Powers Agreement expressly allows the Town to withdraw its
membership in the Marin Energy Authority (and its participation in the Community Choice
295
Aggregation program) prior to the actual implementation of a Community Choice Aggregation
program through Program Agreement 1.
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
implement or operate a Community Choice Aggregation program after the Authority is
established.
SECTION 13. Based upon all of the above, the Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice
Aggregation program within the Town's jurisdiction by and through the Town's participation in
the Marin Energy Authority, as described in the Business Plan in substantially the form attached
hereto as Exhibit B, and subject to the Town's right to forego the actual implementation of a
Community Choice Aggregation program pursuant to specified withdrawal rights described in
the Joint Powers Agreement. The Mayor is hereby authorized to execute the attached Joint
Powers Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption,
and, before the expiration of 30 days after its passage, a summary of this ordinance shall be
published once with the names of the members of the Council voting for and against the same in
the Marin Independent Journal, a newspaper of general circulation published in the county of
Marin.
The foregoing ordinance was introduced at a meeting of the Town Council of the Town
of Ross held on November 13, 2008, and adopted at ameeting held on December 11, 2008, by
the following vote:
AYES:
NOES:
ABSENT:
ABSTAIN:
ATTEST:
Council members Cahill. Hunter. Martin. Skall. Strauss
A¡/da- b-¿*-z'-^-Í
Gary Broad, Town Manager
296
ORDINANCE NO. I Oó7
ORDINANCE OF TIIE TOWN COTINCIL
OF TIIE TOWN OF SAN ANSELMO APPROVING TIIE
MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT AND AUTHORIZING THE
IMPLEMENTATION OF A COMMTINITY CHOICE AGGREGATION
PROGRAM
The Town Council of the Town of San Anselmo ordains as follows:
SECTION 1. The Town of San Anselmo has been actively investigating options to
provide electric services to constituents within its service area with the intent of achieving greater
local involvement over the provisions of electric services and promoting competitive and
renewable energy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill 117
(Stat.2002, ch. 838; see California Public Utilities Code section366.2; hereinafter referred to as
the "Act"), which authorizes any California city or county, whose governing body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the Town has been
participating since 2003 in the evaluation of a CCA program for the County of Marin and the
cities and towns within it.
SECTION 4. On June 22, 2006, the Town joined a Local Government Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin and
each municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin communities and customers. The LGTF had five meetings with
the final meeting taking place on March 6,2008. The LGTF meetings looked at issues including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
Community Choice Aggregation programs, including the recent issuance of a procedure by which
the California Public Utilities Commission will review "Implementation Plans," which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act.
297
SECTION 6. Representatives from the Town along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement")
(attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy" and
(b) To specify the terms and conditions by which participants may participate as
a group in energy programs, including but not limited to the preliminary implementation
of a Community Choice Aggregation program.
SECTION 7. Representatives from the Town along with the LGTF members have
developed a Business Plan (attached hereto as Exhibit B that describes the formation of Marin
Clean Energy and the Community Choice Aggregation program to be implemented by and
through the Marin Energy Authority.
SECTION 8. A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the Authority
as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
(a) To provide greater levels of local involvement in and collaboration on energy
decisions.
(b) To increase significantly the amount of renewable energy available to Marin
customers,
(c) To provide initial price stability, long - term electricity cost savings and other
benefits for the community, and
(d) To reduce green house gases that are emitted by creating electricity for the
communitv.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION I 1. The Joint Powers Agreement expressly allows the Town to withdraw its
membership in the Marin Energy Authority(and its participation in the Community Choice
Aggregation program) prior to the actual implementation of a Community Choice Aggregation
program through Program Agreement 1.
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
298
implement or operate a Community Choice Aggregation program after the Authority is
established.
SECTION 13. Based upon all of the above, the Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice
Aggregation program within the Town's jurisdiction by and through the Town's participation in
the Marin Energy Authority, as described in the Business Plan in substantially the form attached
hereto as Exhibit B, and subject to the Town's right to forego the actual implementation of a
Community Choice Aggregation program pursuant to specified withdrawal rights described in the
Joint Powers Agreement. The Mayor is hereby authorized to execute the attached Joint Powers
Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption,
and, before the expiration of 30 days after its passage, a summary of this ordinance shall be
published once with the names of the members of the Council voting for and against the same in
the Marin IJ, a newspaper of general circulation published in the County of Marin.
The foregoing ordinance was introduced at a meeting of the Town Council of the Town
of San Anselmo. held on November 25. 2008. and at a meeting held on December 9,
2008, by the following vote:
AYES: Freeman, Greene, Thornton
NOES: Breen. House
ABSENT: None
Chambers. Town Clerk
299
300
301
ORDINANCE NO. 187I
(Uncodified)
AN ORDINANCE OF THE CITY OF SAN RAFAEL
APPROVING THE MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT AND
AUTHOzuZING THE IMPLEMENTATION OF
A COMMUNITY CHOICE AGGREGATION PROGRAM
The City Council of the City of San Rafael does hereby ordain as follows:
SECTION 1. The City of San Rafael has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill I 17
(Stat. 2002, ch. 83 8; see California Public Utilities Code section 366.2; hereinafter referred to as
the "Act"), which authorizes any Califomia city or counQr, whose governing body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through ajoint powers agency, and to this end the City of San
Rafael has been participating since 2003 in the evaluation of a CCA program for the County of
Marin and the cities and towns within it.
SECTION 4. On |une22,2006, the City of San Rafaeljoined a Local GovernmentTask
Force (LGTF), which was comprised of elected officials and representatives of the County of
Marin and each municipality within the County of Marin, The purpose of the LGTF was to
jointly participate in the investigation of CCA for Marin communities and customers. The LGTF
had five meetings with the final meeting taking place on March 6, 2008, The LGTF meetings
looked at issues including:
(a) The costs, benefits and risks of a CCA including legal liability issues,
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
Community Choice Aggregation programs, including the recent issuance of a procedure by which
the California Public Utilities Commission will review "lmplementation Plans," which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act.
302
SECTION 6. Representatives from the Cþ of San Rafael along with the other LGTF
members have developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers
Agreement", attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Eneigy Authority"
and,
(b) To specifl, the terms and conditions by which participants may participate as
a group in energy programs, including but not limited to the preliminary implementation
of a Community Choice Aggregation program.
SECTION 7. Representatives from the Cþ of San Rafael along with the LGTF
members have developed a Business Plan (attached hereto as Exhibit B) that describes the
formation of Marin Clean Energy and the Community Choice Aggregation program to be
implemented by and tlrough the Marin Energy Authority.
SECTION 8. A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the Authority
as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
through the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
(a) To provide greater levels of local involvement in and collaboration on energy
decisions.
(b) To increase significantly the amount of renewable energy available to Marin
customers,
(c) To provide initial price stability, long - term electricity cost savings and other
benefits for the community, and
(d) To reduce green house gases which are emitted by creating electricity for the
communitv.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION 1 1. The Joint Powers Agreement expressly allows the City of San Rafael to
withdraw its membership in the Marin Energy Authority (and its participation in the Community
Choice Aggregation program) prior to the actual implementation of a Community Choice
Aggregation program through Program Agreement l.
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program
303
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
implement or operate a Community Choice Aggregation program after the Authority is
established.
SECTION 13. Based upon all of the above, the City Council of the City of San Rafael
approves the Joint Powers Agreement attached hereto as Exhibit A and elects to implement a
Community Choice Aggregation program within the City's jurisdiction by and through the City's
participation in the Marin Energy Authorify, as described in the Business Plan in substantially the
form attached hereto as Exhibit B, and subject to the City's right to forego the actual
implementation of a Community Choice Aggregation program pursuant to specified withdrawal
rights described in the Joint Powers Agreement. The Vice Mayor is hereby authorized to execute
the attached Joint Powers Asreement.
SECTION 14. A summary of this Ordinance shall be published and a certified copy of
the full text of this Ordinance shall be posted in the office of the City Clerk at least five (5) days
prior to the City Council meeting at which it is adopted. This Ordinance shall be in full force and
effect thirry (30) days after its final passage, and the summary of this Ordinance shall be
published within fifteen ( l5) days after the adoption, together with the names of the
Councilmembers voting for or against same, in the Marin Independent Journal, a newspaper of
general circulation published and circulated in the City of San Rafael, County of Marin, State of
California. Within fifteen (15) days after adoption, the City Clerk shall also post in the office of
the City Clerk, a certified copy of the fulltext of this Ordinance along with the names of those
Councilmembers voting for or against the Ordinance
ATTEST:
,futæ* fu-a^-
ESTHER BEIRNE. Ciw Clerk
The foregoing Ordinance No. 1871 was read and introduced at a Regular Meeting of the City
Council of the City of San Rafael, held on the I't day of December, 2008 and ordered passed to print
þy the following vote, to wit:
AYES:
NOES:
Councilmembers: Brockbank, Connolly and Heller
Councilmembers: Vice-MayorMiller
ABSENT: Councilmembers: Mayor Boro, due to potential conflict of interest,
and will come up for adoption as an Ordinance of the Cify of San Rafael at a Regular Meeting of the
Council to be held on the l5th dav of December. 2008.
-41
-2St*-¡z lk¿ P,-<-o
MILLER, Vice Mayor
ESTHER BEIRNE, City Clerk
304
ORDINANCE NO. 1193
AN ORDINANCE OF THE CITY COUNCIL
OF THE CITY OF SAUSALITO APPROVING THE
MARIN ENERGY AUTHORITY
JOINT PO\üERS AGREEMENT AND AUTHORIZING THE
IMPLEMENTATION OF A COMMUNITY CHOICE AGGREGATION
PROGRAM
The City Council of the City of Sausalito ordains as follows:
SECTION 1. The City of Sausalito has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. On September 24,2002, the Governor signed into law Assembly Bill 117
(Stat,2002, Ch 838; see California Public Utilities Code section366.2; hereinafter referred to as
the "Act"), which authorizes any Califomia City or County, whose goveming body so elects, to
combine the electricity load of its residents and businesses in a community-wide electricity
aggregation program known as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes parlicipation in a Community Choice
Aggregation (CCA) program through a joint powers ageîcy, and to this end the City has been
participating since 2003 in the evaluation of a CCA program for the County of Marin and the
cities and towns within.
SECTION 4. On Jtne22,2006, the City joined a Local Government Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin
and each municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin Communities and customers. The LGTF had five meetings with
the final meeting taking place on March 6,2008. The LGTF meetings looked at issues
including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The govemance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
305
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
community choice Aggregation programs, including the recent issuance of a procedure by which
the California Public Utilities commission will review "Implementation Plans", which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act.
SECTION 6. Representatives from the City along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement")
(attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy''and
(b) To specify the terms and conditions by which participants may participate as a group
in energy programs, including but not limited to the preliminary implementation of a
Community Choice Aggregation program.
SECTION 7. Representatives from the City along with the LGTF members have
developed a Business Plan (attached hereto as Exhibit B) that describes the formation of Marin
clean Energy and the Community Choice Aggregation program to be implemented by and
through the Marin Energy Authority.
SECTION 8. A final lmplementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy authority as soon after the formation of the authority
as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation by
and through the Marin Energy authority appears to provide a reasonable opportunity to
accomplish all the following.
(a) To provide greater levels of local involvement in and collaboration on energy
decisions,
(b) To increase significantly the amount of renewable energy avallable to Marin
customers,
(c) To provide initial price stability, long-term electricity cost savings and other benefits
for the community, and
(d) To reduce green house gases that are emitted by creating electricity for the
communitv.
SECTION ,0. ,n. Act requires Community Choice Aggregation program participants
to individually adopt an ordinance ("CCA Ordinance") electing to implement a Community
Choice Aggregation program within its jurisdiction by and through its participation in the Marin
Energy Authority.
306
SECTION 11. The Joint Powers Agreement expressly allows the city to withdraw its
membership in the Marin Energy Authority (and its participation in the Community Choice
Aggregation program) prior to the actual implementation of a Community Choice Aggregation
program through Program Agreement 1.
SECTION 12. A city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
implement or operate a Community Choice Aggregation program after the Authority is
established.
SECTION 13. Based upon all of the above, the Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice
Aggregation program within the City's jurisdiction by and through the City's participation in the
Marin Energy Authority, as described in the Business Plan in substantially the form attached
hereto as Exhibit B, and subject to the City's right to forego the actual implementation of a
Community Choice Aggregation program pursuant to specified withdrawal rights described in
the Joint Powers Agreement. The Mayor is hereby authorized to execute the attached Joint
Powers Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption,
and, before the expiration of 30 days after its passage, a summary of this ordinance shall be
published once with the names and the members of the Council voting for and against the same
in the Marin Scope, a newspaper of general circulation published in the City of Sausalito.
The foregoing ordinance was introduced at a meeting of the City Council of the City of
Sausalito held on November 18, 2008, and adopted at meeting held on November 25,2008, by
the followins vote:
AYES:
NOES:
ABSTAIN:
ABSENT:
Councilmembers:
Councilmembers:
Councilmembers:
Councilmembers:
Albritton, Kelly, Leone, Weiner, and Mayor Belser
None
None
None
MAYOR OF CITY OF SAUSALITO
307
308
309
ORDINANCE NO. 513 N.S,
AN ORDINANCE OF THE TOWN COUNCIL
OF THE TOWN OF TIBURON APPROVING THE
MARIN ENERGY AUTHORITY
JOINT POWERS AGREEMENT AND AUTHORIZING THE
IMPLEMENTATION OF A
COMMLINTTY CHOICE AGGREGATION PROGRAM
The Town Council of the Town of Tiburon ordains as follows:
SECTION 1. The Town of Tiburon has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving greater local
involvement over the provisions of electric services and promoting competitive and renewable
energy.
SECTION 2. Onseptember 24,2002,the Governor signed into law Assembly Bill 117
(Stat.2002, ch. 838; see California Public Utilities Code section366.2; hereinafter referred to as
the "Act"), which authorizes any Califomia city or county, whose governing body so elects, to
combine the elechicity load of its residents and businesses in a community-wide elechicity
aggregation progtam lcrown as Community Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the Town has been
participating since 2003 in the evaluation of a CCA program for the County of Marin and the
cities and towns within it.
SECTION 4. On June 22, 2006, the Town joined a Local Govemment Task Force
(LGTF), which was comprised of elected officials and representatives of the County of Marin and
each municipality in the County. The purpose of the LGTF was to jointly participate in the
investigation of CCA for Marin communities and customers. The LGTF had five meetings with
the final meeting taking place on March 6, 2008. The LGTF meetings looked at issues including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA,
(c) The feasibility of a CCA antl deciding whether to pursue formation of a countywide
CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the Califomia Public Utilities
Commission has issued various decisions and rulings addressing the impiementation of
Community Choice Aggregation programs, including the recent issuance of a procedure by which
the Califomia Public Utilities Commission will review "Implementation Plans," which are
required for submittal under the Act as the means of describing the Community Choice
Aggregation program and assuring compliance with various elements contained in the Act.
Town Council Ordinance No. 513 N.S. Adopted 1I/19/08 Page 1 of3
310
SECTION 6. Representatives from the Town along with the other LGTF members have
developed the Marin Energy Authority Joint Powers Agreement ("Joint Powers Agreement")
(attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy" and
(b) To speci$r the terms and conditions by which participants may participate as
a gfoup in energy programs, including but not limited to the preliminary implementation
of a Community Choice Aggregation program.
SECTION 7. Representatives from the Town along with the LGTF members have
developed a Business Plan (attached hereto as Exhibit B) that describes the formation of Marin
Clean Energy and the Community Choice Aggregation program to be implemented by and
through the Marin Energy Authonty.
SECTION 8. A final Implementation Plan will be submitted for review and adoption by
the Board of Directors of the Marin Energy Authority as soon after the formation of the Authority
as reasonably practicable,
SECTION 9. As described in the Business Plan, Community Choice Aggregation by and
th'rough the Marin Energy Authority appears to provide a reasonable opportunity to accomplish
all of the following:
(a) To provide greater levels of local involvement in and collaboration on energy
decisions.
(b) To increase significantly the amount of renewabie energy available to Marin
customers,
(c) To provide initial price stability, long-term electricity cost savings and other
benefits for the community, and
(d) To reduce green house gases that are emitted by creating electricity for the
communifv.
SECTION 10. The Act requires Community Choice Aggregation program participants to
individually adopt an ordinance ("CCA Ordinance") electing to implement a Community Choice
Aggregation program within its jurisdiction by and through its participation in the Marin Energy
Authority.
SECTION 11. The Joint Powers Agreement expressly allows the Town to withdraw its
membership in the Marin Energy Authority (and its participation in the Communify Choice
Aggregation program) prior to the actual implementation of a Community Choice Aggregation
program through Program Agreement 1.
SECTION 12.
^
city, town or county may not participate in the Marin Energy Joint
Powers Authority without also participating in the Community Choice Aggregation program
unless the Board of Directors of the Marin Energy Joint Powers Authority decides to not
implement or operate a Community Choice Aggregation program after the Authority is
established.
Town Council Ordinqnce No. 513 N.S. Adopted 1l/19/08 Page 2 ofj
311
SECTION 13. Based upon all of the above, the Council approves the Joint Powers
Agreement attached hereto as Exhibit A and elects to implement a Community Choice
Aggregation program within the Town's jurisdiction by and through the Town's participation in
the Marin Energy Authority, as described in the Business Plan in substantially the form attached
hereto as Exhibit B, and subject to the Town's right to forego the actual implementation of a
Community Choice Aggregation program pursuant to specified withdrawal rights described in the
Joint Powers Agreement. The Mayor is hereby authorized to execute the attached Joint Powers
Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its adoption,
and, before the expiration of 30 days after its passage, a summary of this ordinance shall be
published once with the names of the members of the Council voting for and against the same in a
newspapff of general circulation published in the Town of Tiburon.
The foregoing ordinance was introduced at a meeting of the Town Council of the Town
of Tiburon held on November 5, 2008, and adopted at a meeting held on November 19, 2008, by
the following vote:
AYES: COUNCILMEMBERS:
NOES: COLINCILMEMBERS:
ABSENT: COI.JNCILMEMBERS:
Berger, Fredericks, Gram, Slavitz
None
Collins
TFil$ ¡
CE
Town Council Ordinance No. 513 N.S.Adopted I I/19/08 Page 3 of 3
312
313
314
315
316
ORDINANCE NO.3505
ORDINANGE OF THE MARIN GOUNTY BOARD OF SUPERVISORS
APPROVING THE MARIN ENERGY AUTHORITY JOINT POWERS AGREEMENT
AND AUTHORIZING THE IMPLEMENTATION OF A
COMMUNITY CHOICE AGGREGATION PROGRAM
THE BOARD OF SUPERVISORS OF THE COUNTY OF MARIN ORDAINS AS
FOLLOWS:
SECTION l. The County of Marin has been actively investigating options to
provide electric services to constituents within its service area with the intent of
achieving greater local involvement over the provisions of electric services and
promoting competitive and renewable energy.
SECTION 2. On September 24, 2002, the Governor signed into law Assembly
Bill 117 (Stat. 2002, ch. 838; see California Public Utilities Code section 366.2;
hereinafter referred to as the "Act"), which authorizes any California city or county,
whose governing body so elects, to combine the electricity load of its residents and
businesses in a community-wide electricity aggregation program known as Community
Choice Aggregation.
SECTION 3. The Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the Gounty
has been participating since 2003 in the evaluation of a CCA program for the County
and the cities and towns within it.
SECTION 4. On June 22,2006, the County of Marin joined a Local Government
Task Force (LGTF), which was comprised of elected officials and representatives of
each municipality in the County. The purpose of the LGTF was to jointly participate in
the investigation of CCA for Marin communities and customers. The LGTF had five
meetings with the final meeting taking place on March 6, 2008. The LGTF meetings
looked at issues including:
(a) The costs, benefits and risks of a CCA including legal liability issues.
(b) The governance and business planning of a CCA.
(c) The feasibility of a CCA and deciding whether to pursue formation of a
countywide CCA organization.
(d) Public education.
SECTION 5. Through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
Community Choice Aggregation programs, including the.recent issuance of a procedure
by which the California Public Utilities Commission will review "lmplementation Plans,"
which are required for submittal under the Act as the means of describing the
Ordinance No.3505
Page 1 of3
317
Community Choice Aggregation program and assuring compliance with various
elements contained in the Act.
SECTION 6. Representatives from the County along with the other LGTF
members have developed the Marin Energy Authority Joint Powers Agreement ("Joint
Powers Agreement") (attached hereto as Exhibit A) in order to accomplish the following:
(a) To form a Joint Powers Authority (JPA) known as "Marin Energy" and
(b) To specify the terms and conditions by which participants may
participate as a group in energy programs, including but not limited to the
preliminary implementation of a Community Choice Aggregation program.
SECTION 7. Representatives from the County along with the LGTF members
have developed a Business Plan (attached hereto as Exhibit B that describes the
formation of Marin Clean Energy and the Community Choice Aggregation program to be
implemented by and through the Marin Energy Authority.
SECTION 8. A final lmplementation Plan will be submitted for review and
adoption by the Board of Directors of the Marin Energy Authority as soon after the
formation of the Authority as reasonably practicable.
SECTION 9. As described in the Business Plan, Community Choice Aggregation
by and through the Marin Ener:gy Authority appears to provide a reasonable opportunity
to accomplish all of the following:
(a) To provide greater levels of local involvement in and collaboration on
energy decisions.
(b) To increase significantly the amount of renewable energy available to
Marin customers,
(c) To provide initial price stability, long - term electricity cost savings and
other benefits for the community, and
(d) To reduce green house gases that are emitted by creating electricity
for the communitY.
SEGTION 10. The Act requires Community Choice Aggregation program
participants to individually adopt an ordinance ("CCA Ordinance") electing to implement
a Community Choice Aggregation program within its jurisdiction by and through its
participation in the Marin Energy Authority.
SECTION 11. The Joint Powers Agreement expressly allows the County to
withdraw its membership in the Marin Energy Authority (and its participation in the
Community Choice Aggregation program) prior to the actual implementation of a
Community Choice Aggregation program through Program Agreement 1.
Ordinance No. 3505
Page 2 of 3
318
SECTION 12. A city, town or county may not participate in the Marin Energy
Joint Powers Authority without also participating in the Community Choice Aggregation
program unless the Board of Directors of the Marin Energy Joint Powers Authority
decides to not implement or operate a Community Choice Aggregation program after the
Authority is established
SECT¡ON 13. Based upon all of the above, the Board approves the Joint
Powers Agreement attached hereto as Exhibit A and elects to implement a Community
Choice Aggregation program within the County's jurisdiction by and through the County's
participation in the Marin Energy Authority, as described in the Business Plan in
substantially the form attached hereto as Exhibit B, and subject to the County's right to
forego the actual implementation of a Community Choice Aggregation program pursuant
to specified withdrawal rights described in the Joint Powers Agreement. The Chairman
of the Board is hereby authorized to execute the attached Joint Powers Agreement.
SECTION 14. This ordinance shall take effect and be in force 30 days after its
adoption, and, before the expiration of 30 days after its passage, a summary of this
ordinance shall be published once with the names of the members of the Board of
Supervisors voting for and against the same in the Marin lndependent Journal, a
newspaper of general circulation published in the County of Marin.
PASSED AND ADOPTED at a regular meeting of the Board of Supervisors of
the County of Marin held on this 18th day of November, 2008, by the following vote:
AYES:SUPERVISORS Steve Kinsey, Harold C. Brown, Jr., Judy Arnold,
Susan L. Adams. Charles McGlashan
NOES: NONE
ABSENT: NONE
Ø'funæ
PRESIDENT, BOARD OF SUPERVISORS
Ordinance No. 3505
Page 3 of 3
319
320
321
322
MARIN CLEAN ENERGY
REVISED COMMUNITY CHOICE
AGGREGATION
IMPLEMENTATION PLAN AND
STATEMENT OF INTENT
July 18, 2014
For copies of this document contact Marin Clean Energy in San Rafael, California or
visit www.mcecleanenergy.org
APPENDIX D
323
i July 2014
Table of Contents
CHAPTER 1 – Introduction ..................................................................................................................................... 3
Organization of this Implementation Plan ........................................................................................................ 6
CHAPTER 2 – Aggregation Process ....................................................................................................................... 8
Introduction ........................................................................................................................................................... 8
Process of Aggregation ........................................................................................................................................ 8
Consequences of Aggregation ............................................................................................................................ 9
Rate Impacts ................................................................................................................................................ 9
Renewable Energy Impacts ....................................................................................................................... 9
Energy Efficiency Impacts ....................................................................................................................... 10
CHAPTER 3 – Organizational Structure ............................................................................................................. 11
Organizational Overview .................................................................................................................................. 11
Governance .......................................................................................................................................................... 12
Officers ................................................................................................................................................................. 12
Committees .......................................................................................................................................................... 12
Addition/Termination of Participation ............................................................................................................ 12
Agreements Overview ....................................................................................................................................... 13
Joint Powers Agreement .................................................................................................................................... 13
Program Agreement No. 1................................................................................................................................. 13
Agency Operations ............................................................................................................................................. 14
Resource Planning .............................................................................................................................................. 14
Portfolio Operations ........................................................................................................................................... 14
Operations & Local Energy Programs ............................................................................................................. 15
Rate Setting .......................................................................................................................................................... 16
Financial Management/Accounting ................................................................................................................. 16
Customer Services .............................................................................................................................................. 16
Legal and Regulatory Representation .............................................................................................................. 17
Roles and Functions ........................................................................................................................................... 17
Staffing ................................................................................................................................................................. 18
CHAPTER 4 – CCA Startup .................................................................................................................................. 20
Staffing Requirements ........................................................................................................................................ 20
CHAPTER 5 – Program Phase-In ......................................................................................................................... 22
CHAPTER 6 - Load Forecast and Resource Plan ............................................................................................... 23
Introduction ......................................................................................................................................................... 23
Resource Plan Overview .................................................................................................................................... 24
Supply Requirements ......................................................................................................................................... 25
Customer Participation Rates ............................................................................................................................ 25
Customer Forecast .............................................................................................................................................. 26
Sales Forecast ....................................................................................................................................................... 27
Capacity Requirements ...................................................................................................................................... 27
Renewable Portfolio Standards Energy Requirements ................................................................................. 28
Basic RPS Requirements .......................................................................................................................... 28
MCE’s Renewable Portfolio Standards Requirement .......................................................................... 29
Resources ............................................................................................................................................................. 29
Purchased Power ................................................................................................................................................ 30
Renewable Resources ......................................................................................................................................... 30
APPENDIX D
324
ii July 2014
Medium and Long-Term Renewable Potential .................................................................................... 31
Energy Efficiency ................................................................................................................................................ 31
Baseline Energy Efficiency Potential Estimates .................................................................................... 32
CCA Program Energy Efficiency Goals ................................................................................................. 32
Demand Response .................................................................................................................................... 33
Distributed Generation ...................................................................................................................................... 34
CHAPTER 7 – Financial Plan ................................................................................................................................ 36
Description of Cash Flow Analysis .................................................................................................................. 36
Cost of CCA Program Operations .................................................................................................................... 36
Revenues from CCA Program Operations ...................................................................................................... 36
Cash Flow Analysis Results .............................................................................................................................. 37
CCA Program Implementation Feasibility Analysis ..................................................................................... 37
Marin Clean Energy Financings ....................................................................................................................... 38
CCA Program Start-up and Working Capital (Phases 1 and 2) ................................................................... 38
CCA Program Working Capital (Phase 3) ....................................................................................................... 38
CCA Program Working Capital (Phase 4) ....................................................................................................... 39
Renewable Resource Project Financing ........................................................................................................... 39
CHAPTER 8 - Ratesetting and Program Terms and Conditions ...................................................................... 40
Introduction ......................................................................................................................................................... 40
Rate Policies ......................................................................................................................................................... 40
Rate Competitiveness ......................................................................................................................................... 40
Rate Stability ........................................................................................................................................................ 41
Equity among Customer Classes ...................................................................................................................... 41
Customer Understanding .................................................................................................................................. 41
Revenue Sufficiency ........................................................................................................................................... 41
Rate Design .......................................................................................................................................................... 42
Net Energy Metering .......................................................................................................................................... 42
Disclosure and Due Process in Setting Rates and Allocating Costs among Participants ......................... 42
CHAPTER 9 – Customer Rights and Responsibilities ....................................................................................... 44
Customer Notices ............................................................................................................................................... 44
Termination Fee .................................................................................................................................................. 45
Customer Confidentiality .................................................................................................................................. 46
Responsibility for Payment ............................................................................................................................... 46
Customer Deposits ............................................................................................................................................. 46
CHAPTER 10 - Procurement Process ................................................................................................................... 48
Introduction ......................................................................................................................................................... 48
Procurement Methods ........................................................................................................................................ 48
Key Contracts ...................................................................................................................................................... 48
Electric Supply Contract .......................................................................................................................... 48
Data Management Contract .................................................................................................................... 49
Electric Supply Procurement Process .................................................................................................... 50
Shell Energy North America ................................................................................................................... 50
CHAPTER 11 – Contingency Plan for Program Termination .......................................................................... 51
Introduction ......................................................................................................................................................... 51
Termination by Marin Clean Energy ............................................................................................................... 51
Termination by Members .................................................................................................................................. 52
CHAPTER 12 – Appendices .................................................................................................................................. 53
APPENDIX D
325
3 July 2014
CHAPTER 1 – Introduction
Marin Clean Energy (“MCE”; MCE was formerly known as the “Marin Energy Authority” or
“MEA”), a public agency, was formed in December 2008 for the purposes of implementing a
community choice aggregation (“CCA”) program and other energy-related programs targeting
significant greenhouse gas emissions (“GHG”) reductions. At that time, the Member Agencies
of MCE included eight of the twelve municipalities located within the geographic boundaries of
Marin County: the cities/towns of Belvedere, Fairfax, Mill Valley, San Anselmo, San Rafael,
Sausalito and Tiburon and the County of Marin (together the “Members” or “Member
Agencies”). In anticipation of CCA program implementation and in compliance with state law,
MCE submitted the Marin Energy Authority Community Choice Aggregation Implementation
Plan and Statement of Intent (“Implementation Plan”) to the California Public Utilities
Commission (“CPUC” or “Commission”) on December 9, 2009. Consistent with its expressed
intent, MCE successfully launched its CCA program, Marin Clean Energy (“MCE” or
“Program”), on May 7, 2010 and has been successfully serving customers since that time.
During the second half of 2011, four additional municipalities within Marin County, the cities of
Novato and Larkspur and the towns of Ross and Corte Madera, joined MCE, and a revised
Implementation Plan reflecting updates related to said expansion was filed with the CPUC on
December 3, 2011.
Subsequently, the City of Richmond, located in Contra Costa County, joined MCE, and a
revised Implementation Plan reflecting updates related to this expansion was filed with the
CPUC on July 6, 2012.
A revision to MCE’s Implementation Plan was then filed with the Commission on November 6,
2012 to ensure compliance with Commission Decision 12-08-045, which was issued on August
31, 2012. In Decision 12-08-045, the Commission directed existing CCA programs to file revised
Implementation Plans to conform to the privacy rules in Attachment B of this Decision.
Since its expansion to the City of Richmond, numerous communities have contacted MCE
regarding membership opportunities, including specific requests to join MCE and initiate
related CCA service within these respective jurisdictions. In response to these inquiries, MCE’s
governing board adopted Policy 007, which establishes a formal process and specific criteria for
new member additions. In particular, this policy identifies several threshold requirements,
including the specification that any prospective member evaluation demonstrate rate-related
savings (based on prevailing market prices for requisite energy products at the time of each
analysis) as well as environmental benefits (as measured by anticipated reductions in
greenhouse gas emissions and increased renewable energy sales to CCA customers) before
proceeding with expansion activities, including the filing of related revisions to this
Implementation Plan. As MCE receives new membership requests, staff will follow the
prescribed evaluative process of Policy 007 and will present related results at future public
meetings. To the extent that membership evaluations demonstrate favorable results and any
new community completes the process of joining MCE, this Implementation Plan will be
APPENDIX D
326
4 July 2014
revised through an amendment to highlight key impacts and consequences related to the
addition of the new community/communities.
Also, consistent with MCE’s mission statement, MCE launched its first energy efficiency
portfolio in late 2012, initially providing multi-family energy efficiency services to MCE
customers only. In early 2013, MCE launched a portfolio of energy efficiency programs
available to all ratepayers in its service territory, not just MCE customers. Energy efficiency and
other local programs continue to be a robust and growing portion of MCE’s operating activities.
MCE gives electric customers of the Member Agencies an opportunity to procure electricity
from competitive suppliers, with such electricity being delivered over PG&E’s trans mission and
distribution system. To date, the electricity delivered to MCE customers has included over 27
percent Renewables Portfolio Standard (“RPS”) qualifying renewable energy, an amount which
has surpassed all reporting entities, including the incumbent utility. Over the course of MCE’s
phased implementation schedule, all current PG&E customers within MCE’s service area will
receive information describing the Program and will have multiple opportunities to express
their desire to remain bundled customers of PG&E, in which case they will not be enrolled in
the Program. Thus, participation in the CCA Program is completely voluntary; however,
customers, as provided by law, will be automatically enrolled unless they affirmatively elect to
opt-out of the CCA Program.
The MCE program has received considerable interest from other communities in response to its
innovative, environmentally-focused energy service alternative, which now provides electric
generation service to approximately 120,000 customers, including a cross section of residential
and commercial accounts. During its four-year operating history, non-member municipalities
have monitored MCE progress, evaluating the potential opportunity for membership, which
would enable customer choice with respect to electric generation service. In response to public
interest and MCE’s successful operational track record, the County of Napa has requested MCE
membership, consistent with MCE Policy 007, and adopted the requisite ordinances for joining
MCE. MCE’s Board of Directors approved the County of Napa’s membership request at a duly
noticed public meeting on June 5, 2014 (through the approval of Resolution No. 2014-03) and
the County of Napa’s Board of Supervisors completed its final reading of the requisite CCA
ordinance (Ordinance No. 1391) on July 15, 2014.
This revision of the Marin Clean Energy Community Choice Aggregation Implementation Plan
and Statement of Intent (“Revised Implementation Plan”) describes MCE’s expansion plans to
include the County of Napa. According to the Commission, the Energy Division is required to
receive and review a revised MCE implementation plan reflecting changes/consequences of
additional members. With this in mind, MCE has reviewed its revised Implementation Plan,
which was filed with the Commission on November 6, 2012, and has identified certain
information that requires updating to reflect the changes and consequences of adding the new
member and to address MCE’s name change (from MEA to MCE), which occurred via
Resolution No. 2013-11 of MCE’s Governing Board on December 5, 2013. This Revised
Implementation Plan reflects such changes and includes related projections that account for
MCE’s planned expansion.
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Implementation of MCE has enabled customers within MCEs service area to take advantage of
the opportunities granted by Assembly Bill 117 (“AB 117”), the Community Choice Aggregation
Law. MCE’s primary objective in implementing this Program continues to focus on increased
utilization of renewable energy supplies for the purpose of promoting significant GHG
emissions reductions. To date, MCE has achieved this objective by offering customers two
energy supply options: 1) a minimum 50 percent renewable content, which will be the default
service option for participating customers1; or 2) 100 percent renewable content. The
prospective benefits to consumers include a substantial increase in renewable energy supply,
stable and competitive electric rates, public participation in determining which technologies are
utilized to meet local electricity needs, and local/regional economic benefits.
To ensure successful operation of the MCE program, MCE has received assistance from
experienced energy suppliers and contractors in providing energy services to Program
customers. As a result of a competitive solicitation process and subsequent contract
negotiations, a highly qualified firm, Shell Energy North America (“SENA”) was selected as
MCE’s initial energy services provider and scheduling coordinator. Since this initial
solicitation, MCE has completed numerous procurement activities in an effort to accommodate
the increasing electric energy requirements of a growing customer base, including the execution
of various power purchase agreements with new and existing renewable energy projects. Such
purchases have served to diversify MCE’s energy supply portfolio, reflecting the use of multiple
fuel sources, contract term lengths and resource locations, among other considerations. To
serve the increasing energy requirements resulting from expanded membership MCE
anticipates that its existing supply agreement with SENA may be amended and/or
supplemented with additional purchases from other qualified suppliers of requisite energy
products to reflect the Program’s increased future needs. Information regarding SENA is
contained in Chapter 10.
MCE’s Implementation Plan reflects a collaborative effort among MCE, its Members, and the
private sector to bring the benefits of competition and choice to Member residents and
businesses. By exercising its legal right to form a CCA Program, MCE has enabled its Members’
constituents to access the competitive market for energy services and obtain access to increased
renewable energy supplies and resultant reductions in GHG emissions. Absent action by MCE
or its individual Members, most customers would have no ability to choose an electric supplier
and would remain captive customers of their incumbent utility.
The California Public Utilities Code provides the relevant legal authority for MCE to become a
Community Choice Aggregator and invests the California Public Utilities Commission
(“CPUC” or “Commission”) with the responsibility for establishing the cost recovery
mechanism that must be in place before customers can begin receiving electrical service through
MCE’s CCA Program. The CPUC has also registered MCE as a Community Choice Aggregator
and continues to ensure compliance with basic consumer protection rules. The Public Utilities
Code requires that an Implementation Plan be adopted at a duly noticed public hearing and
1 MCE customers received nearly 29 percent RPS-qualifying renewable energy in 2013. The default renewable energy
content, which includes RPS-qualifying renewable energy and supplemental renewable energy credit purchases, was
voluntarily increased from 25% to 50% beginning in January, 2012.
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that it be filed with the Commission in order for the Commission to determine the cost recovery
mechanism to be paid by customers of the Program in order to prevent shifting of costs. Each of
these milestones has been accomplished. The Commission has established the methodology
that will be used to determine the cost recovery mechanism, and PG&E now has approved
tariffs for imposition of the cost recovery mechanism. Finally, each of MCE’s Members has
adopted an ordinance to implement a CCA program through its participation in MCE (copies of
the ordinance adopted by MCE’s newest member, the County of Napa, is included as Appendix
D). Following the CPUC’s certification of its receipt of this Revised Implementation Plan and
resolution of any outstanding issues, MCE will take the final steps needed to expand CCA
service to MCE’s new member, including customer notification and enrollment.
Organization of this Implementation Plan
The content of this Revised Implementation Plan complies with the statutory requirements of
AB 117. Because MCE has already successfully implemented its CCA program, this Revised
Implementation Plan includes narrative discussion, updates and projections focused on on-
going operation and expansion of the MCE program rather than previously completed
implementation efforts. As a result, certain sections of this document are now substantially
abbreviated. Consistent with requirements identified in PU Code Section 366.2(c)(4), this
Revised Implementation Plan addresses:
Universal access;
Reliability;
Equitable treatment of all customer classes; and
Any requirements established by state law or by the CPUC concerning aggregated
service.
To promote consistency with MCE’s original January 25, 2010 Implementation Plan, the
remainder of this Revised Implementation Plan is organized as follows:
Chapter 2: Aggregation Process
Chapter 3: Organizational Structure
Chapter 4: CCA Startup
Chapter 5: Program Phase-In
Chapter 6: Load Forecast and Resource Plan
Chapter 7: Financial Plan
Chapter 8: Ratesetting
Chapter 9: Customer Rights and Responsibilities
Chapter 10: Procurement Process
Chapter 11: Contingency Plan for Program Termination
Appendix A: Marin Clean Energy Resolution 2014-03
Appendix B: County of Napa, Resolution 2014-59
Appendix C: Joint Powers Agreement
Appendix D: County of Napa, CCA Ordinance – Ordinance No. 1391
The requirements of AB 117 are cross-referenced to Chapters of this Implementation Plan in the
following table.
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AB 117 Cross References
AB 117 REQUIREMENT IMPLEMENTATION PLAN CHAPTER
Process and consequences of aggregation Chapter 2: Aggregation Process
Organizational structure of the program,
its operations and funding
Chapter 3: Organizational Structure
Chapter 4: Startup Plan and Funding
Chapter 7: Financial Plan
Ratesetting and other costs to participants Chapter 8: Ratesetting
Chapter 9: Customer Rights and
Responsibilities
Disclosure and due process in setting rates
and allocating costs among participants
Chapter 8: Ratesetting
Methods for entering and terminating
agreements with other entities
Chapter 10: Procurement Process
Participant rights and responsibilities Chapter 9: Customer Rights and
Responsibilities
Termination of the program Chapter 11: Contingency Plan for Program
Termination
Description of third parties that will be
supplying electricity under the program,
including information about financial,
technical and operational capabilities
Chapter 10: Procurement Process
Statement of Intent Chapter 1: Introduction
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CHAPTER 2 – Aggregation Process
Introduction
As previously noted, MCE successfully launched its CCA Program, MCE, on May 7, 2010 after
meeting applicable statutory requirements and in consideration of planning elements described
in its January 25, 2010 Implementation Plan. At this point in time, MCE plans to expand agency
membership to include the County of Napa. This community has requested MCE membership,
and MCE’s Board of Directors subsequently approved the membership request at a duly
noticed public meeting.
As planned, the residents and businesses within MCE’s expanded service territory will be
offered electric generation service from MCE’s currently operating CCA program, MCE, which
represents a culmination of planning efforts that are responsive to the expressed needs and
priorities of the citizenry and business community within the region. Through the MCE
program eligible customers have received expanded energy choices, including the creation of a
100% renewable energy product and 100% local solar product. In effect, MCE provides Marin
residents and businesses with four electric service options, which include: 1) the default 50%
(minimum) renewable energy service option – Light Green; 2) a 100% renewable energy service
option – Deep Green – which can be chosen on a voluntary basis; 3) a 100% local solar energy
service option – Sol Shares – in which customers can enroll on a voluntary basis2; or 4) bundled
energy service from the incumbent utility. It remains MCE’s long-term goal to supply its
customers entirely with clean, renewable energy, subject to economic and operational
constraints.
Each of the Member Agencies has adopted an ordinance to implement a CCA program through
its participation in MCE. A Revised Implementation Plan was adopted at a duly noticed public
hearing of MCE on June 5, 2014.
Process of Aggregation
All customers currently enrolled in the MCE program were appropriately noticed. Before
additional phases of customers are enrolled in the Program, MCE will mail at least two written
notices to customers, beginning at least two calendar months, or sixty days, in advance of the
date of commencing automatic enrollment, that will provide information needed to understand
the Program’s terms and conditions of service and explain how these customers can opt-out of
the Program, if desired. All customers that do not follow the opt-out process specified in the
customer notices will be automatically enrolled, and service will begin at their next regularly
scheduled meter read date at least one calendar month, or thirty days following the date of
automatic enrollment, subject to the service phase-in plan described in Chapter 5. At least two
follow-up opt-out notices will be mailed to these customers within the first two calendar
months, or sixty days, of service.
2 The Sol Shares program is currently accepting customer enrollments but will not begin delivering electric power to
participating customers until the 2015 calendar year. In the meantime, Sol Shares enrollees may continue taking
MCE service under the Light Green or Deep Green service options.
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Customers enrolled in the Program will continue to have their electric meters read and be billed
for electric service by the distribution utility (PG&E). The electric bill for Program customers
will show separate charges for generation procured by the Program and all other charges
related to delivery of the electricity and other utility charges that will continue to be assessed by
PG&E.
After service cutover, customers will be given two additional opportunities to opt-out of the
Program and return to the distribution utility (PG&E) following receipt of their first and second
bills. Customers that opt-out between the initial cutover date and the close of the post
enrollment opt-out period will be responsible for program charges for the time they were
served by MCE but will not otherwise be subject to any penalty for leaving the program.
Customers that have not opted-out within thirty days of the fourth opt-out notice will be
deemed to have elected to become a participant in the Program and to have agreed to the
Program’s terms and conditions, including those pertaining to requests for termination of
service, as further described in Chapter 8.
Consequences of Aggregation
Rate Impacts
Customers will pay the generation charges set by MCE and no longer pay the costs of PG&E
generation. Customers enrolled in the Program will be subject to the Program’s terms and
conditions, including responsibility for payment of all Program charges as described in Chapter
9. MCE’s rate setting policies are described in Chapter 7. MCE will establish rates sufficient to
recover all costs related to operation of the Program, and actual rates will be adopted by MCE’s
governing board.
Information regarding current Program rates will be disclosed along with other terms and
conditions of service in the pre-enrollment opt-out notices sent to potential customers.
Program customers are not expected to be responsible in any way for costs associated with the
utilities’ future electricity procurement contracts or power plant investments that are made on
behalf of utility bundled service customers. Certain pre-existing generation costs will continue
to be charged by PG&E to CCA customers through a separate rate component, called the Cost
Responsibility Surcharge or CRS. This charge is shown in PG&E’s tariff, which can be accessed
from the utility’s website.
Renewable Energy Impacts
The MCE program has substantially increased the proportion of energy generated and supplied
to its customers by renewable resources. The resource plan includes procurement of renewable
energy sufficient to meet a minimum of 50 percent of the Program’s electricity needs.
Customers of MCE may voluntarily participate in a 100 percent renewable supply option. To
the extent that customers choose to participate in this voluntary program, the renewable content
of MCE’s power supply would increase. The renewable energy requirements of MCE
customers are being supplied through contractual arrangements, but may be delivered, at an
indeterminate point in the future, by new renewable generation resources developed by or for
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MCE subject to then-current considerations (such as development costs, regulatory
requirements and other concerns).
Energy Efficiency Impacts
Energy efficiency is an important component of the MCE mission statement. MCE currently
administers over $4 million in ratepayer funded energy efficiency programs under the purview
of the California Public Utilities Commission. MCE launched energy efficiency programs in late
2012 under the authority of Public Utilities Code section 381.1 (e-f). This 2012 plan focused
specifically on providing multi-family energy efficiency services to MCE customers only. In
early 2013, MCE launched a full portfolio of energy efficiency services, available to all
ratepayers in MCE service territory, under the authority in PUC 381.1 (a-d). Energy efficiency is
included in the MCE Integrated Resources Plan, and both local energy efficiency potential and
energy efficiency accomplishments are utilized to inform future estimates of procurement
needs. This relationship is described further in Chapter 6.
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CHAPTER 3 – Organizational Structure
This section provides an overview of the organizational structure of MCE
Organizational Overview
The MCE program is governed by MCE’s Board of Directors (“Board”), appointed by the
Members. MCE is a joint powers agency created in December 2008 and formed under
California law. Originally, the County of Marin and eight municipalities within the geographic
boundaries of the County became Members of MCE and elected to offer the Program to their
constituents. Since that time, the remaining four municipalities within Marin, which include
the cities of Novato and Larkspur and the towns of Ross and Corte Madera, have requested and
received approval for MCE membership as has the City of Richmond and, most recently, the
County of Napa. MCE (formerly known as “The Marin Energy Authority”) is the CCA entity
that has registered with the CPUC and has been responsible for implementing and managing
the program pursuant to MCE’s Joint Powers Agreement (“JPA Agreement” or “Agreement”).
The Program is operated under the direction of an Executive Officer, who has been appointed
by the Board. The Executive Officer reports to the Board comprised of one representative from
each participating Member of MCE. Those who are eligible to serve as representatives on the
Board include elected officials from the then-current County Board of Supervisors representing
Marin County as well as the County of Napa (one Board representative has been selected from
the Marin County Board of Supervisors; another Board representative, who will soon begin
serving on MCE’s governing board, has been selected by the County of Napa’s Board of
Supervisors) and the City and Town Councils (one representative has been selected from each
of the City and Town Councils) of the Members.
The Board’s primary duties are to establish program policies, set rates and provide policy
direction to the Executive Officer, who has general responsibility for program operations,
consistent with the policies established by the Board. The Board has also determined necessary
staffing levels, individual titles and related compensation ranges for the organization. The
Board may also adjust staffing levels and compensation over time in response to varying
workloads, specific programs and/or general responsibilities of MCE.
The Executive Officer is an employee of MCE, and the Board is responsible for evaluating the
Executive Officer’s performance.
The Board has established a Chairman and other officers from among its membership and has
established an Executive Committee and Technical Committee and may establish other
committees and sub-committees as needed to address issues that require greater expertise in
particular areas (e.g., finance or contracts). MCE may also establish an “Energy Commission”
formed of Board-selected designees. The Energy Commission would have responsibility for
evaluating various issues that may affect MCE and its customers, including rate setting, and
would provide analytical support and recommendations to the Board in these regards.
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The Executive Officer has responsibilities over the functional areas of Finance, Regulatory
Affairs, and Operations. In performing these responsibilities, the Executive Officer utilizes a
combination of internal staff and contractors. Certain specialized functions needed for program
operations, namely the electric supply and customer account management functions described
below, are performed by experienced third-party contractors.
Governance
MCE has a Board of Directors consisting of one representative from each Member. Following
satisfaction of certain administrative conditions, the Board will soon add an additional
representative from the County of Napa. The Board meets at regular intervals to provide the
overall management and guidance for MCE. All Board meetings are public and held in
accordance with the Ralph M. Brown Act.
Decisions by MCE are under voting procedures defined in the JPA Agreement, attached hereto
as Appendix C. All votes on a particular matter are subject to the two-tiered approval process
described in the JPA Agreement.
Officers
MCE has a Chair and Vice-Chair elected to one-year terms by the Board of Directors. Both the
Chair and Vice-Chair must be members of the Board. In addition, MCE has a Board Clerk and
Auditor; neither of which will be members of the Board of Directors. The JPA Agreement
provides further detail with respect to each of these positions.
Committees
MCE may form various committees comprised of Board designees from the Member
communities. Appointments would be made based on various skill sets and expertise that will
be useful in evaluating matters affecting MCE and its customers, specifically issues related to
rate setting, procurement of energy products and other technical matters. These committees
would provide the Board with recommendations and related analysis to support policy-level
decisions of the Board. MCE may elect to have additional committees or working groups to
address various topics. Any additional committees and their functions will be determined by
the Board of Directors at the time each committee is created. At present, MCE has formed the
following standing committees: 1) the Executive Committee; and 2) the Technical Committee.
MCE also utilizes Ad Hoc Committees from time to time on an as-needed basis.
Addition/Termination of Participation
The JPA Agreement provides for the addition of new participants subject to the affirmative vote
of MCE’s Board of Directors pursuant to the voting structure described in the Agreement. The
Board has determined the specific terms and conditions under which new Members can be
admitted and has recently approved the membership request received from the County of
Napa. Following the satisfaction of certain administrative requirements determined by the
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Board, a representative from the new Member will be added to the Board and will begin
participating in governance activities.
A JPA Member can withdraw itself from the JPA subject to the specific terms and conditions
contained in the JPA Agreement.
Agreements Overview
There are two principal agreements that govern MCE and the initial operation of its CCA
Program: the JPA Agreement and Program Agreement No. 1 (PA-1). Each of these agreements
and its functions are discussed below.
Joint Powers Agreement
The JPA Agreement created MCE and delineates a broad set of powers related to the study,
promotion, development, and conduct of electricity-related projects and programs. The JPA
Agreement describes MCE as having broad powers, but a very limited role without
implementing agreements (“program agreements”) to carry out specific programs. This
structure is intended to provide flexibility for MCE to undertake other programs in the future
that may be unrelated to CCA on behalf of all or a subset of MCE’s Members. The Board has
limited decision making authority regarding land use within the Member communities. Any
issues involving land use within Member communities will be raised with the potentially
affected Member. The land use and building regulations of each Member shall apply to any
JPA facilities located within the jurisdiction of that Member. Any amendments to the JPA
Agreement will be subject to prior approval by the Board.
The first program agreement or PA-1, discussed in greater detail below, provides for electric
generation service to customers of the CCA Program. At MCE’s Members’ discretion, future
program agreements could provide for other energy related programs or subsequent energy
transactions.
Program Agreement No. 1
PA-1 consists of three components: 1) the Edison Electric Institute (“EEI”) Master Power
Purchase & Sale Agreement (“Master EEI Agreement”), which is a standard industry contract
used by public and private utilities across the United States; 2) the EEI Master Power Purchase
& Sale Agreement Cover Sheet, which provides additional detail related to MCE’s specific
transaction, identifying exceptions, clarifications and areas of applicability that modify the
standard terms and conditions of the Master EEI Agreement; and 3) one or more Confirmations,
inclusive of any amendments thereto, which is referenced in the Master EEI Agreement and
defines the commercial terms of MCE’s transaction. PA-1 is the agreement under which MCE
currently procures a significant portion of the electric supply services for MCE customers. PA-1
specifies a five year delivery period, which commenced on May 7, 2010 and ends on May 6,
2015. PA-1 specifies a full requirements energy product, including electric energy, renewable
energy, capacity, ancillary services and scheduling coordination services. Based on contract
negotiations, PA-1 specifies fixed annual prices for each year of the delivery period and
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insulates municipal funds/budgets of the Member Agencies before, during and after the
delivery period. PA-1 was executed by MCE and its energy supplier, SENA, on February 5,
2010 and has since incorporated a series of amendments to accommodate Program expansion.
It is MCE’s intent to provide for the additional energy requirements of future MCE customers
by negotiating other contracts for requisite energy products and/or subsequent amendments to
PA-1, which will be completed prior to commencement of service to CCA customers located
within the unincorporated areas of the County of Napa. MCE anticipates that SENA will
continue in its role as MCE’s primary energy supplier and scheduling coordinator over the
near-term (through December 31, 2016) but will also pursue supply arrangements with
renewable energy generators to supplement planned renewable energy deliveries from SENA.
Agency Operations
MCE conducts program operations through its own internal staff and through contracts for
services with third parties. MCE has its own General Counsel to manage its legal affairs.
MCE’s Executive Officer will have responsibility for day-to-day operations of the Program. To
assist the Executive Officer, MCE has hired a full-time Administrative Assistant and a Clerk.
Other staff positions may be added as necessary to include positions in finance, customer
services, energy efficiency and other local energy programs, and operations.
Major MCE functions that are performed and managed by the Executive Officer are
summarized below.
Resource Planning
MCE is charged with developing both short (one and two-year) and long-term resource plans
for the program. The Executive Officer manages staff and contractors to develop the resource
plan under the guidance provided by the Board and in compliance with California Law, and
other requirements of California regulatory bodies (CPUC and CEC).
Long-term resource planning includes load forecasting and supply planning on a ten- to
twenty-year time horizon. MCE’s technical team develops integrated resource plans that meet
program supply objectives and balance cost, risk and environmental considerations. Integrated
resource planning considers demand side energy efficiency and demand response programs as
well as traditional supply options. The CCA Program requires an independent planning
function despite day-to-day supply operations being contracted to a third party energy
supplier. Plans are updated and adopted by the Board on an annual basis.
Portfolio Operations
Portfolio operations encompass the activities necessary for wholesale procurement of electricity
to serve end use customers. These highly specialized activities include the following:
Electricity Procurement – assemble a portfolio of electricity resources to supply the electric
needs of program customers.
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Risk Management – standard industry techniques are employed to reduce exposure to the
volatility of energy markets and insulate customer rates from sudden changes in
wholesale market prices.
Load Forecasting – develop accurate load forecasts, both long-term for resource planning
and short-term for the electricity purchases and sales needed to maintain a balance
between hourly resources and loads.
Scheduling Coordination – scheduling and settling electric supply transactions with the
CAISO.
MCE has initially contracted with an experienced and financially sound third party, SENA, to
perform most of the portfolio operation requirements for the CCA Program. These
requirements include the procurement of energy and ancillary services, scheduling coordinator
services, and day-ahead and real-time trading. PA-1 is the contractual instrument that has been
developed for this purpose; additional detail related to PA-1 is provided in the preceding
discussion.
MCE will approve and adopt a set of Program Controls that will serve as the risk management
tools for the Executive Officer and any third party involved in the program’s portfolio
operations. Program Controls will define risk management policies and procedures and a
process for ensuring compliance throughout the organization. During initial operations, SENA
will bear the majority of program operational risks, pursuant to the terms and conditions of PA-
1.
Operations & Local Energy Programs
A key focus of the CCA Program will be the development and implementation of local energy
programs for its Members, including energy efficiency programs, net energy metering,
distributed generation programs and other energy programs responsive to Member interests.
The Executive Officer is responsible for further development of these Programs. To assist the
Executive Officer in this regard, MCE has hired additional staff to oversee program operations
and local energy program administration as well as develop energy efficiency marketing
strategies, perform customer outreach and conduct related analyses to support chosen courses
of action. As experience is gained from the retail energy side of the CCA Program, MCE will
continue enhancing its local energy programs to achieve MCE’s desired goals and objectives.
MCE is currently administering energy efficiency and distributed (solar) generation programs
that can be used as alternatives to procurement of supply-side resources. MCE may also
implement demand response programs in the future. For the time being, MCE has launched
various small-scale pilot projects to explore demand response opportunities within its service
territory. MCE will attempt to consolidate existing demand side programs into this
organization and leverage the structure to expand energy efficiency offerings to customers
throughout its service territory.
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Rate Setting
The Board of Directors has the ultimate responsibility for setting the electric generation rates for
the Program’s customers. The Executive Officer in cooperation with technical staff and
appropriate advisors, consultants and committees of the Board is responsible for developing
proposed rates and options for the Board to consider before finalization. The final approved
rates must, at a minimum, meet the annual revenue requirement developed by the Executive
Officer, including any reserves or coverage requirements set forth in electric supply agreements
and/or bond covenants. The Board has the flexibility to consider rate adjustments within
certain ranges, provided that the overall revenue requirement is achieved; this provides an
opportunity for economic development rates or other rate incentives.
Financial Management/Accounting
The Executive Officer in cooperation with technical staff, advisors and consultants is
responsible for managing the financial affairs of MCE, including the development of an annual
budget and revenue requirement; managing and maintaining cash flow requirements; potential
bridge loans and other financial tools; and a large volume of billing settlements. The Executive
Officer uses contractors and/or staff in support of these activities, as appropriate.
The Finance function arranges financing for capital projects, prepares financial reports, and
ensures sufficient cash flow for the Program. This function also plays an important role in risk
management by monitoring the credit of suppliers so that credit risk is properly understood
and mitigated by the Program. In the event that changes in a supplier’s financial condition
and/or credit rating are identified, the Program will be able to take appropriate action, as would
be provided for in the electric supply agreement. The Finance function establishes credit
policies that the program must follow.
The retail settlements (customer billing) is contracted out to an organization with the necessary
infrastructure and capability to handle in excess of 138,000 accounts during full Program phase-
in and near-term expansion (to the County of Napa), which is scheduled to occur in February
2015. This function is described under Customer Services, below.
Customer Services
In addition to general program communications and marketing, a significant focus on customer
service, particularly representation for key accounts, is necessary. This includes both a call
center designed to field customer inquiries and routine interaction with customer accounts. The
Executive Officer is responsible for the Customer Services function and uses staff and/or
contractors in support of these activities as appropriate.
The Customer Account Services function performs retail settlements-related duties and
manages customer account data. It processes customer service requests and administers
customer enrollments and departures from the Program, maintaining a current database of
customers enrolled in the Program. This function coordinates the issuance of monthly bills
through the distribution utility’s billing process and tracks customer payments. Activities
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include the electronic exchange of usage, billing, and payments data with the distribution utility
and MCE, tracking of customer payments and accounts receivable, issuance of late payment
and/or service termination notices, and administration of customer deposits in accordance with
MCE credit policies.
The Customer Account Services function also manages billing related communications with
customers, customer call centers, and routine customer notices. MCE has initially contracted
with a third party, Noble Americas Energy Solutions (“Noble”), which has demonstrated the
necessary experience and administers appropriate computer systems (customer information
system), to perform the customer account and billing services functions.
MCE conducts Program marketing and key customer account management functions. These
responsibilities will include the assignment of account representatives to key accounts, which
will ensure high levels of customer service to these businesses, and implementation of a
marketing strategy to promote customer satisfaction with the CCA Program. Effectively
administering communications, marketing messages, and delivering information regarding the
CCA Program to all customers is critical for the overall success of the CCA Program.
Legal and Regulatory Representation
The CCA Program requires ongoing regulatory representation to file resource plans, resource
adequacy, compliance with California RPS, and overall representation on issues that will impact
MCE, its Members and MCE customers. MCE maintains an active role at the CPUC, CEC, and,
as necessary, FERC and the California legislature. Day-to-day analysis and reporting of
pertinent legal and regulatory issues is completed by the Program’s in-house legal and
regulatory staff and/or qualified contractors.
MCE also retains legal services, as necessary, to administer MCE, review contracts, and provide
overall legal support to the activities of MCE.
Roles and Functions
The Board performs the functions inherent in its policy-making, management and planning
roles. MCE is the public face of the Program and has a direct role in marketing,
communications and customer service. Other highly specialized functions, such as energy
supply and data management, are contracted out to third parties with sufficient experience,
technical and financial capabilities. The functions that are currently being performed by MCE’s
Board of Directors, the Executive Officer and third parties are specified below:
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18 July 2014
Organization Roles/Functions/Activities
MCE Board of Directors Executive/Policy/Legal
Executive Officer
Finance
Legal and Regulatory
- Legal support
- Participation in regulatory proceedings
- Regulatory reporting
Marketing/Communications
Rates & Support
- Rate policy
- Rate design
- Cost-of-service planning
Resource Planning
- Load research
- Load forecasting
- Supply-side/Demand side portfolio planning
Supply Operations
- Procurement
- Contract Negotiation
- Invoice Reconciliation
Contract Management
- RFP/RFQ Administration
- Invoice Reconciliation & Issue Resolution
- Project Development Status Monitoring
Customer Service
- Account representatives
- Energy efficiency/DG program management
Energy Suppliers Supply Operations
- Procurement
- Scheduling coordination
- Settlements (ISO/Wholesale)
- Short-term load forecasting
Customer Account Services
Provider/Data Manager (Noble)
Account Management (Customer Information System)
- Customer switching
- New customer processing
- Data exchange (EDI)
- Payment processing (AR/AP)
- Billing and retail settlements
- Call center
Staffing
Staffing requirements for the above MCE functions will be approximately ten full time
equivalent positions, once the customer phase-in is complete and the program is fully
operational. These staffing requirements are in addition to the services provided by the third
party energy suppliers and the data manager. The Executive Officer will have discretion
whether to internally staff these required functions or to contract for these services.
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19 July 2014
The following table shows the staffing plan for Marin Clean Energy at initial full-scale
operational levels, following full phase-in. Customer service for the mass market residential
and small commercial customers will be provided by the Program’s third party customer
account services provider.
Current Staffing for the Marin Clean Energy
Community Choice Aggregation Program
Longer-term staffing needs will include additional energy efficiency and distributed generation
activities and potentially the creation of an internal organization to perform the portfolio
operations and account services functions that are currently performed under contract
arrangements.
Position Staff (Full Time Equivalents)
Executive Officer 1
Director of Internal Operations 1
Business Analyst 1
Clerk 1
Human Resources Coordinator 0.5
Administrative Associate 1
Communications Director 1
Manager of Account Services 1
Account Manager 1 2
Community Affairs Coordinator 1
Communications Associate 1
Energy Efficiency Director 1
Energy Efficiency Specialist 2
Legal Director 1
Regulatory Counsel 1
Regulatory Analyst 1
Regulatory Assistant 1
Director of Power Resources 1
Program Specialist 1
Special Assignment Intern 0.5
Total Staffing 21
Internal Operations
Public Affairs
Energy Efficiency
Legal & Regulatory
Electric Supply
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CHAPTER 4 – CCA Startup
As previously noted, MCE successfully launched the MCE program on May 7, 2010. To ensure
successful operation during the implementation and start-up period, MCE utilized a mix of staff
and contractors in its CCA Program implementation. The following table illustrates start-up
responsibilities as well as expectations for near-term (two to five years), and long-term staffing
roles.
Expectations for Staffing Roles
Function Start-Up
Near-Term
(2 to 5 Years) Long-Term
Program Governance MCE Board MCE Board MCE Board
Program Management MCE EO MCE EO MCE EO
Outreach MCE EO MCE EO MCE EO
Customer Service MCE EO MCE EO MCE EO
Key Account Management MCE EO MCE EO MCE EO
Regulatory Third Party
(MCE EO support)
MCE EO
(Regulatory Analyst
support)
MCE EO
(Regulatory
Analyst support)
Legal MCE EO MCE EO MCE EO
Finance MCE EO MCE EO MCE EO
Rates: Develop & Approve
MCE EO
(third Party support)
MCE Board
MCE EO
(third Party support)
MCE Board
MCE EO
(third party
support)
MCE Board
Resource Planning Third Party
(MCE EO support)
MCE EO (third
party support)
MCE EO (third
party support)
Energy Efficiency MCE EM
(third Party
Support)
MCE EO (Program
Energy Efficiency
Staff)
MCE EO (Program
Energy Efficiency
Staff)
Resource Development MCE EO (third
party support)
MCE EO (third
party support)
MCE EO (third
party support)
Portfolio Operations Third Party Third Party
(MCE EO support)
MCE EO (third
party support)
Scheduling Coordinator Third Party Third Party Third Party
(potentially MCE
EO)
Data Management Third Party Third Party Third Party
(potentially MCE
EO)
Staffing Requirements
Staff will be added incrementally to match workloads involved in forming the new
organization, managing contracts, and initiating customer outreach/marketing during the pre-
operations period. Actual staff will be dependent upon several factors, including the ability to
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21 July 2014
recruit and hire qualified staff and personnel policies ultimately established by the Executive
Officer and the Board of Directors.
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CHAPTER 5 – Program Phase-In
MCE will continue to phase-in the customers of its CCA Program as communicated in this
Implementation Plan. To date, four phases have been successfully implemented, and a fifth
phase will commence in February 2015.
Phase 1. Complete: MCE Member (municipal) accounts & a subset of residential,
commercial and/or industrial accounts, comprising approximately 20 percent of
total customer load.
Phase 2. Complete: Additional commercial and residential accounts, comprising an
approximately 20 percent of total customer load (incremental addition to Phase
1).
Phase 3. Complete: Remaining accounts within Marin County.
Phase 4. Complete: Residential, commercial, agricultural, and street lighting accounts
within the City of Richmond.
Phase 5. February 2015: Residential, commercial, agricultural, and street lighting accounts
within the unincorporated areas of Napa County, subject to economic and
operational constraints.
This approach has provided MCE with the ability to start slow, addressing any problems or
unforeseen challenges on a small manageable program before gradually building to full
program integration for an expected customer base of approximately 138,000 accounts,
following service commencement to customers within the unincorporated areas of the County
of Napa. This approach has also allowed MCE and its energy supplier(s) to address all system
requirements (billing, collections, payments) under a phase-in approach to minimize potential
exposure to uncertainty and financial risk by “walking” prior to ultimately “running”.
MCE will offer service to all customers on a phased basis expected to be completed within
twenty four to thirty six months of initial service to Phase 1 customers, which occurred on May
7, 2010. Phase 2 was implemented in August, 2011. Phase 3 of the Program began in July, 2012.
Phase 4 was implemented in July, 2013 and included all residential, commercial, agricultural,
and street lighting customers within the City of Richmond. Phase 5 is planned to begin in
February 2015 and will include all residential, commercial, agricultural, and street lighting
customers within the unincorporated areas of Napa County. The Board may evaluate other
phase-in options based on then-current market conditions, statutory requirements and
regulatory considerations as well as other factors potentially affecting the integration of
additional customer accounts.
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CHAPTER 6 - Load Forecast and Resource Plan
Introduction
This Chapter describes MCE’s proposed ten-year integrated resource plan, which will create a
highly renewable, diversified portfolio of electricity supplies capable of meeting the electric
demands of MCE’s retail customers, plus sufficient reliability reserves.
This integrated resource plan reflects a progression towards MCE’s long-term, programmatic
goal of 100 percent renewable energy supply. Within five years of program commencement
(2015), this significant commitment to renewable resources is projected to result in MCE
meeting approximately 52 percent of its total electric needs through renewable resources. As
the Program moves forward, incremental renewable supply additions will be made based on
resource availability as well as economic goals of the Program. MCE’s aggressive commitment
to renewable generation adoption may involve both direct investment in new renewable
generating resources through partnerships with experienced public power
developers/operators, significant purchases of renewable energy from third party suppliers and
the purchase of Renewable Energy Certificates (“RECs”) from the market. The resource plan
also sets forth ambitious targets for improving customer side energy efficiency as well as for
potential deployment of approximately 14 MW of new distributed solar capacity within the
jurisdictional boundaries of MCE by 2019 (year ten of Program operations).
The plan described in this section would accomplish the following by 2019:
Procure energy needed to offer two generation rate tariffs: 100 percent Deep Green and
50 percent (minimum) Light Green.
Increase the aggregate RPS-eligible renewable energy supply of the Program to a
minimum 33 percent by 2020.
Continue increasing renewable energy supplies of the Program to approximately 52
percent by 2015 based on resource availability and economic goals of the program.
Develop partnership(s) with experienced public power developer(s) to responsibly
evaluate development opportunities for Program-owned/controlled renewable
generating capacity.
Achieve significant reductions in greenhouse gas emissions within the Member
Agencies.
MCE is responsible for complying with regulatory rules applicable to California load serving
entities. MCE has arranged for the scheduling of sufficient electric supplies to meet the hour-
by-hour demands of its customers. MCE has adhered to capacity reserve requirements
established by the CPUC and the CAISO designed to address uncertainty in load forecasts and
potential supply disruptions caused by generator outages and/or transmission contingencies.
These rules also ensure that physical generation capacity is in place to serve the Program’s
customers, even if there were to be a need for the Program to cease operations and return
customers to PG&E. In addition, MCE is responsible for ensuring that its resource mix contains
sufficient production from renewable energy resources needed to comply with the statewide
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24 July 2014
renewable portfolio standards. The resource plan will meet or exceed all of the applicable
regulatory requirements related to resource adequacy and the renewable portfolio standard.
Resource Plan Overview
The criteria used to guide development of the proposed resource plan included the following:
Environmental responsibility and commitment to renewable resources;
Price/rate stability;
Reliability and maintenance of adequate reserves; and
Cost effectiveness.
To meet these objectives and the applicable regulatory requirements, MCE’s resource plan
includes a diverse mix of power purchases, renewable energy, new energy efficiency programs,
demand response, and distributed generation. A diversified resource plan minimizes risk and
volatility that can occur from over-reliance on a single resource type or fuel source. The
ultimate goal of MCE’s resource plan is to maximize use of renewable resources subject to
economic and operational constraints. The result is a resource plan that will source
approximately 52 percent of MCE’s resource mix from renewable resources by 2015. The
planned resource mix is initially comprised of power and renewable energy credit purchases
from third party electric suppliers and, in the longer-term, may also include renewable
generation assets owned and/or controlled by MCE.
Eventually, MCE may begin evaluating opportunities for investment in renewable generating
assets, subject to then-current market conditions, statutory requirements and regulatory
considerations. Any renewable generation owned by MCE or controlled under long-term
power purchase agreement with a proven public power developer, could provide a portion of
MCE’s electricity requirements on a cost-of-service basis. Electricity purchased under a cost-of-
service arrangement should be more cost-effective than purchasing renewable energy from
third party developers, which will allow the Program to pass on cost savings to its customers
through competitive generation rates. Any investment decisions will be made following
thorough environmental reviews and in consultation with the Marin Communities’ financial
advisors, investment bankers, attorneys, and potentially with customer input.
As an alternative to direct investment, MCE may consider partnering with an experienced
public power developer and enter into a long-term (20-to-30 year) power purchase agreement
that would support the development of new renewable generating capacity. Such an
arrangement could be structured to greatly reduce the Program’s operational risk associated
with capacity ownership while providing Program customers with all renewable energy
generated by the facility under contract. This option may be preferable to MCE as it works to
achieve increasing levels of renewable energy supply to its customers.
MCE’s resource plan will integrate supply-side resources with programs that will help
customers reduce their energy costs through improved energy efficiency and other demand-
side measures. As part of its integrated resource plan, MCE will actively pursue, promote and
ultimately administer a variety of customer energy efficiency programs that can cost-effectively
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displace supply-side resources. Included in this plan is a targeted deployment of over 14 MW
of distributed solar by 2019.
MCE’s proposed resource plan for the years 2010 through 2019 is summarized in the following
table:
Supply Requirements
The starting point for MCE’s resource plan is a projection of participating customers and
associated electric consumption. Projected electric consumption is evaluated on an hourly
basis, and matched with resources best suited to serving the aggregate of hourly demands or
the program’s “load profile”. The electric sales forecast and load profile will be affected by
MCE’s plan to introduce the Program to customers in phases and the degree to which
customers choose to remain with PG&E during the customer enrollment and opt-out periods. It
is anticipated that MCE’s contracted energy supplier will bear a portion of the financial risks
associated with deviations from the electric sales forecast during the initial operating period. It
will be the obligation of this energy supplier to appropriately reflect these risks in the full
requirements energy price. MCE’s phased roll-out plan and assumptions regarding customer
participation rates are discussed below.
Customer Participation Rates
Customers will be automatically enrolled in MCE’s electricity program unless they opt-out
during the customer notification process conducted during the 60-day period prior to
enrollment and continuing through the 60-day period following commencement of service.
MCE anticipated an overall customer participation rate of approximately 80 percent during
Phase 1, when service is being offered to the service accounts that are affiliated with MCE’s
participating members (municipal accounts) and a subset of residential, commercial and/or
industrial customers, totaling approximately 20 percent of total customer load. The actual
participation rate for Phase 1 was very similar to MCE’s projection. Participation rates for
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Demand (GWh)
Retail Demand -91 -185 -570 -1,110 -1,294 -1,545 -1,582 -1,582 -1,582 -1,582
Distributed Generation 0 1 1 5 12 16 22 23 25 25
Energy Efficiency 0 0 0 6 6 4 8 12 16 16
Losses and UFE -5 -11 -34 -66 -77 -91 -93 -93 -92 -92
Total Demand -96 -196 -603 -1,166 -1,353 -1,616 -1,646 -1,640 -1,634 -1,634
MCE Supply (GWh)
Renewable Resources
Generation 0 0 0 0 0 0 0 219 219 219
Power Purchase Contracts 23 50 291 566 673 803 838 635 651 667
Total Renewable Resources 23 50 291 566 673 803 838 854 870 886
Conventional Resources
Generation 0 0 0 0 0 0 0 0 0 0
Power Purchase Contracts 73 146 312 599 680 813 807 786 764 748
Total Conventional Resources 73 146 312 599 680 813 807 786 764 748
Total Supply 96 196 603 1,166 1,353 1,616 1,646 1,640 1,634 1,634
Energy Open Position (GWh)0 0 0 0 0 0 0 0 0 0
2010 to 2019
Marin Clean Energy
Proposed Resource Plan
(GWH)
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26 July 2014
Phase 2 were approximately 80 percent of bundled service customers and 0 percent of direct
access customers. Participation rates for Phases 3 and 4 are projected to range from 70 percent
to 80 percent, with the lower figure used as the basis for load projections contained in this plan .
The participation rate is not expected to vary significantly among customer classes, in part due
to the fact that MCE will offer two distinct rate tariffs that will address the needs of cost-
sensitive customers within the Marin Communities as well as the needs of both residential and
business customers that prefer a highly renewable energy product. The assumed participation
rates will be refined as MCE’s public outreach and market research efforts continue to develop.
Customer Forecast
Once customers enroll in each phase, they will be switched over to service by MCE on their
regularly scheduled meter read date over an approximately thirty day period. The number of
accounts served by MCE at the end of each phase is shown in the table below.
Marin Clean Energy
Enrolled Retail Service Accounts
Phase-In Period (End of Month)
May-10 Aug-11 Jul-12 Jul-13 Feb-15
MCE Customers
Residential 7,354 12,503 77,345 106,510 120,204
Small Commercial 522 605 8,934 11,829 13,761
Medium And Large
Commercial And
Industrial
57 509 949
1,269
1,555
Street Lighting & Traffic 138 141 443 748 1,014
Ag & Pump. - < 15 113 109 1,467
Total 8,071 13,759 87,814 120,465 138,001
MCE assumes that MCE customer growth will generally offset customer attrition (opt-outs)
over time, resulting in a relatively stable customer base over the noted planning horizon.
Because MCE is the first program of its kind within California, it is very difficult to anticipate
with any precision the actual levels of customer participation within this CCA program. MCE
believes that its assumptions regarding the offsetting effects of growth and attrition are
reasonable in consideration of the limited build-out potential within a significant portion of
MCE’s service territory and the observed rate of customer opt-outs following mandatory
customer notification periods. The forecast of service accounts (customers) served by MCE for
each of the referenced ten-year planning periods is shown in the following table:
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Marin Clean Energy
Retail Service Accounts (End of Year)
2010 to 2019
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Customers
Residential 7,354 12,503 77,345 106,510 106,510 120,204 120,204 120,204 120,204 120,204
Small Commercial 522 605 8,934 11,829 11,829 13,761 13,761 13,761 13,761 13,761
Medium And Large Commercial And
Industrial
57
509
979
1,269
1,269
1,555
1,555
1,555
1,555
1,555
Street Lighting & Traffic 138 141 443 748 748 1,014 1,014 1,014 1,014 1,014
Ag & Pump. - < 15 113 109 109 1,467 1,467 1,467 1,467 1,467
Total 8,071 13,759 87,814 120,465 120,465 138,001 138,001 138,001 138,001 138,001
Sales Forecast
MCE’s forecast of kWh sales reflects the roll-out and customer enrollment schedule shown
above. The annual electricity needed to serve MCE’s retail customers increases from
approximately 200 GWh in 2011 to approximately 1,600 GWh at full roll-out, which includes
planned expansion to the County of Napa. Annual energy requirements are shown below.
Capacity Requirements
The CPUC’s resource adequacy standards applicable to MCE require a demonstration one year
in advance that MCE has secured physical capacity for 90 percent of its projected peak loads for
each of the five months May through September, plus a minimum 15 percent reserve margin.
On a month-ahead basis, MCE must demonstrate 100 percent of the peak load plus a minimum
15 percent reserve margin.
A portion of MCE’s capacity requirements must be procured locally, from the Greater Bay area
as defined by the CAISO and another portion must be procured from local reliability areas
outside the Greater Bay Area. MCE must also meet requirements for flexible capacity such that
a portion of MCE’s resource adequacy requirements are met from qualifying flexible resources.
MCE is required to demonstrate its local and flexible capacity requirements for each month of
the following calendar year. MCE must demonstrate compliance or request a waiver from the
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Energy Requirements (GWh)
Retail Demand 91 185 570 1,110 1,294 1,545 1,582 1,582 1,582 1,582
Distributed Generation 0 -1 -1 -5 -12 -16 -22 -23 -25 -25
Energy Efficiency 0 0 0 -6 -6 -4 -8 -12 -16 -16
Losses and UFE 5 11 34 66 77 91 93 93 92 92
Total Load Requirement 96 196 603 1,166 1,353 1,616 1,646 1,640 1,634 1,634
2010 to 2019
Marin Clean Energy
Energy Requirements
(GWH)
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28 July 2014
CPUC requirement as provided for in cases where local capacity is not available. MCE
complies with the forward and monthly resource adequacy requirements administered by the
state regulatory agencies.
MCE’s plan ensures sufficient reserves are procured to meet its peak load at all times. MCE’s
annual peak capacity requirements are shown in the following table:
MCE will continue to coordinate with PG&E and appropriate state agencies to manage the
transition of responsibility for resource adequacy from PG&E to MCE following load migration
to CCA service. For system resource adequacy requirements, MCE will make month-ahead
showings for each month that MCE plans to serve load, and any load migration issues will be
addressed through the CPUC’s approved procedures. MCE will work with the California
Energy Commission and CPUC prior to commencing service to additional customers to ensure
it meets its local, system and flexible resource adequacy obligations through its agreements with
its chosen electric suppliers.
Renewable Portfolio Standards Energy Requirements
Basic RPS Requirements
As a CCA, MCE is required by law and ensuing CPUC regulations to procure a certain
minimum percentage of its retail electricity sales from qualified renewable energy resources.
For purposes of determining MCE’s renewable energy requirements, the same standards for
RPS compliance that are applicable to the distribution utilities are assumed to apply to MCE.
California’s RPS program is currently undergoing reform. On April 12, 2011, Governor Jerry
Brown signed SB x1 2, requiring public and private utilities as well as community choice
aggregators to obtain 33 percent of their electricity from renewable energy sources by December
31, 2020. MCE is familiar with California’s new RPS, including certain procurement quantity
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Demand (MW)
Retail Demand 28 46 182 233 233 286 286 286 286 286
Distributed Generation (0) (1) (4) (8) (11) (15) (15) (17) (17) (17)
Energy Efficiency - - - (1) (1) (1) (2) (3) (3) (3)
Losses and UFE 2 3 11 13 13 16 16 16 16 16
Total Net Peak Demand 30 47 189 237 235 287 285 283 282 282
Reserve Requirement (%)15% 15% 15% 15% 15% 15% 15% 15% 15% 15%
Capacity Reserve Requirement 4 7 28 36 35 43 43 42 42 42
Capacity Requirement Including Reserve 34 55 218 273 270 330 328 325 324 324
2010 to 2019
Marin Clean Energy
Capacity Requirements
(MW)
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29 July 2014
requirements identified in D.11-12-020 (December 1, 2011). To date, MCE has significantly
exceeded California’s RPS, providing MCE customers with over 29 percent RPS-eligible
renewable energy delivered to MCE customers in 2012. A similar renewable energy percentage,
approximating 28.7 percent, was supplied to MCE customers in 2013.
MCE’s Renewable Portfolio Standards Requirement
MCE’s annual RPS requirements are shown in the table below. When reviewing this table, it is
important to note that MCE projects increases in energy efficiency savings as well as increases
in locally situated distributed generation capacity (an additional 14 MW by 2019), resulting in a
slight downward trend in projected retail electricity sales.
Based on planned renewable energy procurement objectives, MCE anticipates that it will
significantly exceed the minimum RPS requirements as shown below.
Resources
MCE has begun evaluating opportunities for future investment in renewable generating assets.
Such opportunities will be evaluated on a case by case basis in consideration of resource
location, market conditions, statutory requirements and regulatory considerations. Any
renewable generation owned by MCE or controlled under long-term power purchase
agreement with a proven public power developer, could provide a portion of MCE’s electricity
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Retail Sales 91,219 185,493 570,144 1,110,487 1,293,681 1,544,971 1,581,999 1,581,999 1,581,999 1,581,999
Baseline - 18,244 37,099 114,029 222,097 280,729 359,978 395,500 427,140 458,780
Incremental Procurement Target 18,244 18,855 76,930 108,069 58,631 79,249 35,522 31,640 31,640 31,640
Annual Procurement Target 18,244 37,099 114,029 222,097 280,729 359,978 395,500 427,140 458,780 490,420
% of Current Year Retail Sales 20% 20% 20% 20% 22% 23% 25% 27% 29% 31%
2010 to 2019
Marin Clean Energy
RPS Requirements
(MWH)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Retail Sales (MWh)91,219 185,493 570,144 1,110,487 1,293,681 1,544,971 1,581,999 1,581,999 1,581,999 1,581,999
Annual RPS Target (Minimum MWh) 18,244 37,099 114,029 222,097 280,729 359,978 395,500 427,140 458,780 490,420
Program Target (% of Retail Sales)25% 27% 51% 51% 52% 52% 53% 54% 55% 56%
Program Renewable Target (MWh)22,805 50,083 290,773 566,348 672,714 803,385 838,459 854,279 870,099 885,919
Surplus In Excess of RPS (MWh)4,561 12,984 176,745 344,251 391,985 443,407 442,960 427,140 411,320 395,500
Annual Increase (MWh)22,805 27,278 240,690 275,575 106,366 130,671 35,075 15,820 15,820 15,820
2010 to 2019
Marin Clean Energy
RPS Requirements and Program Renewable Energy Targets
(MWH)
APPENDIX D
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30 July 2014
requirements on a cost-of-service basis. Electricity purchased under a cost-of-service
arrangement should be more cost-effective than purchasing renewable energy from third party
developers, which will allow the Program to pass on cost savings to its customers through
competitive generation rates. Any investment decisions will be made following thorough
environmental reviews and in consultation with MCE’s financial advisors, investment bankers,
attorneys, and potentially with customer input.
As an alternative to direct investment, MCE may consider partnering with an experienced
public power developer and enter into a long-term (20-to-30 year) power purchase agreement
that would support the development of new renewable generating capacity. Such an
arrangement could be structured to greatly reduce the Program’s operational risk associated
with capacity ownership while providing Program customers with all renewable energy
generated by the facility under contract. This option may be preferable to MCE as it works to
achieve increasing levels of renewable energy supply to its customers.
Purchased Power
Power purchased from utilities, power marketers, public agencies, and/or generators will likely
be the predominant source of supply from 2010 to 2015 (MCE may consider the development of
certain renewable energy projects, subject to Board approval, which may supply electric
generation to MCE customers as soon as January 2016) and may still remain a significant source
of power in the event that MCE considers the development of its own renewable generation
assets. During the period from 2010 – 2016, MCE plans to contract with SENA for a substantial
portion of its electricity needs under a full requirements power supply agreement, and SENA
will be responsible for procuring a mix of power purchase contracts, including specified
renewable energy targets, to provide a stable and cost-effective resource portfolio for the
Program. Deliveries under this agreement have been supplemented with purchases of other
energy products from qualified renewable project developers, asset owners and power
marketers. Based on terms established in this third-party contract, MCE will continue to
substitute electric energy generated by MCE-owned/controlled renewable resources for contract
quantities in the event that such resources become operational during the delivery period.
Renewable Resources
MCE will initially secure necessary renewable power supply from SENA. MCE has
supplemented the renewable energy provided under the initial full requirements contract with
direct purchases of renewable energy from renewable energy facilities.
For planning purposes, MCE should anticipate procurement from the following types of large
scale renewable resources in the near to midterm, which would require little or no transmission
expansion to ensure deliverability:
Local resources (solar, wind, biogas, biomass);
Wind resources in Solano County;
Existing Qualifying Facilities with expiring PG&E contracts;
Expansion and re-powering of wind resources in Alameda County;
Geothermal in Lake and Sonoma Counties;
Local biomass projects; and
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31 July 2014
Renewable Energy Certificates.
Medium and Long-Term Renewable Potential
For mid and long term planning purposes, MCE should anticipate procurement from the
following types of large scale renewable resources3:
Wind imports from the Tehachapi Area;
Wind imports from the Pacific Northwest;
Geothermal imports from Nevada;
Geothermal imports from the Imperial Valley;
Photovoltaic solar imports from California’s Central Valley; and
Solar CSP imports from Southern California (Riverside and San Bernardino Counties).
Although this resource plan identifies likely resource types and locations, it is not possible to
predict what projects might be proposed in response to MCE’s future solicitations for renewable
energy or that may stem from discussions with other public agencies. Renewable projects that
are located virtually anywhere in the Western Interconnection can be considered as long as the
electricity is deliverable to the CAISO control area, as required to meet the Commission’s RPS
rules and any additional guidelines ultimately adopted by MCE’s Board of Directors. The costs
of transmission access and the risk of transmission congestion costs would need to be
considered in the bid evaluation process if the delivery point is outside of MCE’s load zone, as
defined by the CAISO.
Energy Efficiency
This section addresses the treatment of energy efficiency as a component of MCE’s integrated
resource plan. As described below there are opportunities for significant cost effective energy
efficiency programs within the region, and MCE will seek to maximize end-use customer
energy efficiency to the greatest extent practical. MCE first received funding to implement
energy efficiency programs through the ‘elect to administer’ portion of the Public Utilities Code
(section 381.1 e-f), wherein MCE has the authority to collect funds which have already been
collected from MCE customers to support an energy efficiency plan that complies with the
legislative intent. MCE submitted a plan for the use of 2012 program funding, focusing
exclusively on multi-family customers; this plan was certified by the Commission in August,
2012.4
On a parallel track, MCE submitted an application to administer funds as an independent
program administrator, an option which was clarified by SB 790 (2011) and reinforced in a
recent CPUC Decision on CCA and Energy Efficiency5. This suite of programs offers energy
efficiency services for multi-family, small commercial and single family sectors with financing
3 In the long term, new technologies such as wave or tidal energy may become economically feasible as well.
4 Resolution E-4815 California Public Utilities Commission. August 23, 2012.
5 Decision 14-01-033. Decision Enabling Community Choice Aggregators to Administer Energy Efficiency Programs.
January 16, 2014.
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programs available to support all programs. MCE plans to grow the energy efficiency and local
program department over time.
Baseline Energy Efficiency Potential Estimates
The National Action Plan for Energy Efficiency states among its key findings “consistently
funded, well-designed efficiency programs are cutting annual savings for a given program year
of 0.15 to 1 percent of energy sales.”6 The American Council for an Energy-Efficient Economy
(ACEEE) reports for states already operating substantial energy efficiency programs energy
efficiency goals of one percent, as a percentage of energy sales, is a reasonable level to target.7
Forecast achievable energy efficiency equal to one percent of the CCA’s forecast energy sales, as
indicated in the table below, appears to be a reasonable and conservative baseline for the
demand-side portion of CCA’s resource plan. Targeted program savings would be in addition
to the savings achieved by PG&E administered programs.
CCA Program Energy Efficiency Goals
The Program’s energy efficiency goals reflect a strong commitment to increa sing energy
efficiency within the County and expanding beyond the savings achieved by PG&E’s programs.
MCE’s goal is to increase annual savings through energy efficiency programs to two percent
(combined MCE and PG&E programs) of annualized electric sales, as has been adopted by the
State of New York, by the end of 2018. Achieving this goal would mean at least a doubling of
energy savings relative to the status quo situation without the CCA program. MCE programs
will focus on closing the gap between the vast economic potential of energy efficiency within
MCE’s service territory and what is actually achieved, while designing programs based on
community input that align with MCE’s mission statement.
The following table summarizes the estimated energy efficiency potential for each type of
energy efficiency initiative:8
6 National Action Plan for Energy Efficiency, July 2006, Section 6: Energy Efficiency Program Best Practices (pages 5-
6)
7 Energy Efficiency Resource Standards: Experience and Recommendations, Steve Nadel, March 2006, ACEEE Report
E063 (pages 28 - 30).
8 California Energy Efficiency Potential Study Volume 1, California Measurement Advisory Council (CALMAC)
Study ID: PGE0211.01, May 24, 2006, Figure 12-2: Distribution of Electric Energy Market Potential, Existing Incentive
Levels through 2016.
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MCE Retail Demand 91 185 570 1,110 1,294 1,545 1,582 1,582 1,582 1,582
MCE Energy Efficiency Goal 0 0 0 -6 -6 -4 -8 -12 -16 -16
Energy Efficiency Savings Goals
(GWH)
2010 to 2019
Marin Clean Energy
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California Energy Efficiency Market Potential
EXISTING RESIDENTIAL 53.0%
Existing Commercial 18.0%
Existing Industrial 14.0%
Residential New Construction 1.0%
Commercial New Construction 6.0%
Industrial New Construction 1.0%
Emerging Technologies 7.0%
The retrofit of existing buildings represents 85 percent of the total forecast energy efficiency
market potential. Studies show that the residential customer sector presents the largest
untapped efficiency gains.
MCE has ramped up the Energy Efficiency department since the first funding authorization in
late 2012. MCE’s energy efficiency department continues to refine energy savings estimates and
develop portfolios in line with customer expectations and local patterns of energy use.
Additional details of MCE’s energy efficiency plans are set forth in a separate planning
document.9
Demand Response
Demand response programs provide incentives to customers to reduce demand upon request
by the load serving entity (i.e., MCE), reducing the amount of generation capacity that must be
maintained as infrequently used reserves. Demand response programs can be cost effective
alternatives to capacity otherwise needed to comply with the resource adequacy requirements.
The programs also provide rate benefits to customers who have the flexibility to reduce or shift
consumption for relatively short periods of time when generation capacity is most scarce. Like
energy efficiency, demand response can be a win/win proposition, providing economic benefits
to the electric supplier and customer service benefits to the customer.
In its ruling on local resource adequacy, the CPUC found that dispatchable demand response
resources as well as distributed generation resources should be allowed to count for local
capacity requirements. MCE has launched several small scale pilots to explore the possibilities
for local DR programs. This resource plan anticipates that MCE’s demand response programs
would partially offset its local capacity requirements beginning in 2016.
PG&E offers several demand response programs to its customers, and MCE intends to recruit
those customers that have shown a willingness to participate in utility programs into MCE’s
demand response programs.10 The goal for this resource plan is to meet 5 percent of the
Program’s total capacity requirements (by 2018) through dispatchable demand response
9 Marin Energy Authority’s Proposal to Administer Energy Efficiency Programs Pursuant to Public Utilities Code
381.1(e) and (f) for 2012, June 22, 2012.
10 These utility programs include the Base Interruptible Program (E-BIP), the Demand Bidding Program (E-DBP),
Critical Peak Pricing (E-CPP), Optional Binding Mandatory Curtailment Plan (E-OBMC), the Scheduled Load
Reduction Program (E-SLRP), and the Capacity Bidding Program (E-CBP). MCE has started to develop and
implement its own demand response programs on a pilot basis.
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programs that qualify to meet local resource adequacy requirements. This goal translates into
approximately 13 MW of peak demand enrolled in MCE’s demand response programs.
Achievement of this goal would displace approximately 32 percent of MCE’s local capacity
requirement within the Greater Bay Area.
MCE’s initial DR pilots offer the opportunity to explore DR programs and develop
administrative capabilities related to this component of the MCE service offering. MCE plans to
leverage experiences and lessons learned from these initial pilots to develop a demand response
program that enables it to request customer demand reductions during times when capacity is
in short supply or spot market energy costs are exceptionally high. The level of customer
payments should be related to the cost of local capacity that can be avoided as a result of the
customer’s willingness to curtail usage upon request.
Appropriate limits on customer curtailments, both in terms of the length of individual
curtailments and the total number of curtailment hours that can be called should be included in
MCE’s demand response program design. It will also be important to establish a reasonable
measurement protocol for customer performance of its curtailment obligations. Performance
measurement should include establishing a customer specific baseline of usage prior to the
curtailment request from which demand reductions can be measured. MCE will likely utilize
experienced third party contractors to design, implement and administer its demand response
programs.
Distributed Generation
Consistent with MCE’s environmental policies and the state’s Energy Action Plan, clean
distributed generation is a significant component of the integrated resource plan. MCE will
work with state agencies and PG&E to promote deployment of photovoltaic (PV) systems
within MCE’s jurisdiction, with the goal of maximizing use of the available incentives that are
funded through current utility distribution rates and public goods surcharges. MCE has also
implemented an aggressive net energy metering program to promote local investment in
distributed generation.
There are significant associated environmental benefits and strong customer interest in
distributed PV systems. The economics of PV should improve over time as utility rates
continue to increase and the costs of the systems decline with technological improvements and
added manufacturing capacity. MCE can also promote distributed PV without providing direct
financial assistance by being a source of unbiased consumer information and by facilitating
customer purchases of PV systems through established networks of pre-qualified vendors. It
may also provide direct financial incentives from revenues funded by customer rates to further
support use of solar power within the Marin Communities. As previously noted, MCE has
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Total Capacity Requirement (MW)34 55 218 273 270 330 328 325 324 324
Demand Response Target - - - - - - 4 12 16 16
Percentage of Local Capacity Requirment 0% 0% 0% 0% 0% 0% 8% 24% 32% 32%
Marin Clean Energy
Demand Response Goals
(MW)
2010 to 2019
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provided direct incentives for PV by offering an aggressive net metering rate to customers who
install PV systems so that customers are able to sell excess energy to MCE.
MCE’s CCA customers will contribute funds to the California Solar Initiative (CSI) through the
public goods charge collected by PG&E, and will be eligible for the incentives provided under
that program for installation of PV systems. The California Solar Initiative provides $2.2 billion
of funding to target installation of 1,940 MW of solar systems within the investor owned utility
service areas by 2017. All electric customers of PG&E, SCE, and SDG&E are eligible to apply for
incentives. Approximately 44 percent of program funding is allocated to the PG&E service
territory. Assuming solar deployment would be proportionate to funding, the program is
intended to yield approximately 775 MW of solar within the PG&E service area. A minimum of
17 MW should be deployed within the service territory of MCE.
MCE will work to ensure that customers within its jurisdiction take full advantage of this solar
incentive and will develop programs of its own with the goal of doubling the CSI deployment
targets shown above.
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
IOU Territory Target (MW)705 882 1,058 1,235 1,411 1,587 1,764 1,940 1,940 1,940
Total Funding ($Millions)240 240 240 160 160 160 5 0 0 0
PG&E Funding ($Millions)105 105 105 70 70 70 2 0 0 0
PG&E Incentives Share 44% 44% 44% 44% 44% 44% 40% 40% 40% 40%
PG&E Area Deployment (MW)309 386 463 540 617 694 705 776 776 776
MCE Share of PG&E Load 0.1% 0.3% 0.8% 1.5% 1.8% 2.1% 2.1% 2.1% 2.1% 2.1%
MCE Solar Deployment (MW)0 1 4 8 11 15 15 17 17 17
California Solar Initiative Deployment
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CHAPTER 7 – Financial Plan
This Chapter examines the monthly cash flows expected during the phase-in period of the CCA
Program and identifies the anticipated financing requirements for the overall CCA Program by
MCE. It also describes the requirements for working capital and long-term financing for the
potential investment in renewable generation, consistent with the resource plan contained in
Chapter 6.
Description of Cash Flow Analysis
This cash flow analysis estimates the level of working capital that will be required during the
phase-in period. In general, the components of the cash flow analysis can be summarized into
two distinct categories: (1) Cost of CCA Program Operations, and (2) Revenues from CCA
Program Operations. The cash flow analysis identifies and provides monthly estimates for each
of these two categories. A key aspect of the cash flow analysis is to focus primarily on the
monthly costs and revenues associated with the CCA Program phase-in period, and specifically
account for the transition or “Phase-In” of CCA Customers from PG&E’s service territory
described in Chapter 5.
Cost of CCA Program Operations
The first category of the cash flow analysis is the Cost of CCA Program Operations. To estimate
the overall costs associated with CCA Program Operations, the following components were
taken into consideration:
Electricity Procurement;
Ancillary Service Requirements;
Exit Fees;
Staffing Requirements;
Contractor Costs;
Infrastructure Requirements;
Billing Costs;
Scheduling Coordination;
Grid Management Charges;
CCA Bond Premiums;
Interest Expense; and
Franchise Fees.
The focus of this cash flow analysis is during the phase-in period.
Revenues from CCA Program Operations
The cash flow analysis also provides estimates for revenues generated from CCA operations or
from electricity sales to customers. In determining the level of revenues, the cash flow analysis
assumes the customer phase-in schedule noted above, and assumes that MCE’s CCA Program
provides a Light Green Tariff at comparable generation rates to those of the existing distribution
utility for each customer class and a 100 percent Green Tariff at a premium reflective of
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incremental renewable power costs. A third service option, which is planned to begin serving
customers during the 2015 calendar year, is Sol Shares. The voluntary Sol Shares service option
will supply participating customers with 100 percent locally generated solar electricity – MCE is
currently accepting enrollments in the Sol Shares program.
Over time, MCE’s preference for renewable energy will significantly reduce its exposure to
volatile input costs (fuel – natural gas) associated with natural gas-fired generation, which are
expected to increase steadily, and potentially significantly, for the foreseeable future. Because a
significant portion of MCE’s power supply will be from renewable energy sources, upward
price pressures on its power supply should be significantly reduced over long-term operations.
Projected long-term cost savings can be passed on to Program customers in the form of lower
generation rates or can be applied to the procurement of additional renewable energy supplies
(moving the program’s renewable energy supply closer to its 100 percent goal), energy
efficiency programs or other energy/climate initiatives within the scope of broad-based powers
established for MCE. Ultimately, MCE will have flexibility when making these decisions and
can respond to the evolving needs of local residents and businesses when developing rate tariffs
and energy/climate-focused programs.
Cash Flow Analysis Results
The results of the cash flow analysis provide an estimate of the level of working capital required
for MCE to move through the CCA phase-in period. This estimated level of working capital is
determined by examining the monthly cumulative net cash flows (revenues from CCA
operations minus cost of CCA operations) based on assumptions for payment of costs by MCE,
along with an assumption for when customer payments will be received. This identifies, on a
monthly basis, what level of cash flow is available in terms of a surplus or deficit.
With the assumptions regarding payment streams, the cash flow analysis identifies funding
requirements while recognizing the potential lag between payments received and payments
made during the phase-in period. The estimated financing requirements for the phase-in
period, including working capital, based on the phase-in of customers as described above is
approximately $3 million. Working capital requirements reach this peak immediately after
enrollment of the Phase 3 customers.
CCA Program Implementation Feasibility Analysis
In addition to developing a cash flow analysis which estimates the level of working capital
required to get MCE through full CCA phase-in, a summary analysis that evaluates the
feasibility of the CCA program during the phase-in period has been prepared. The difference
between the cash flow analysis and the CCA feasibility analysis is that the feasibility analysis
does not include a lag associated with payment streams. In essence, costs and revenues are
reflected in the month in which service is provided. All other items, such as costs associated
with CCA Program operations and rates charged to customers remain the same.
The results of the feasibility analysis are shown in the following table. Under these
assumptions, over the entire phase-in period the CCA program is projected to accrue a reserve
account balance of approximately $17 million.
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The surpluses achieved during the phase-in period serve as operating reserves for MCE in the
event that operating costs (such as power purchase costs) exceed collected revenues for short
periods of time.
Marin Clean Energy Financings
It is anticipated that three financings may be necessary in support of the CCA Program. The
anticipated financings are listed below and discussed in greater detail.
CCA Program Start-up and Working Capital (Phases 1 and 2)
As previously discussed, the start-up and working capital requirements for the CCA Program
were approximately $2 million. These costs are currently being recovered from retail customers
through retail rates.
CCA Program Working Capital (Phase 3)
Working capital for Phase 3 was $3 million financed through a short term credit agreement
from a commercial bank.
CCA Program Working Capital (Phase 4)
MCE utilized existing, internally generated funds to cover costs associated with the Phase 4
customer expansion.
CATEGORY 2010 2011 2012 2013 2014 2015
I. REVENUES FROM OPERATIONS ($)
ELECTRIC SALES REVENUE 10,610,804 16,454,790 44,052,111 79,097,747 100,075,912 125,116,985
LESS UNCOLLECTIBLE ACCOUNTS (21,453) (102,807) (220,261) (395,489) (500,380) (625,585)
TOTAL REVENUES 10,589,351 16,351,983 43,831,851 78,702,259 99,575,532 124,491,400
II. COST OF OPERATIONS ($)
(A) ADMINISTRATIVE AND GENERAL (A&G)
STAFFING 321,117 430,659 1,077,759 1,386,303 1,825,000 1,993,875
CONTRACT SERVICES 1,035,333 848,063 3,131,840 4,457,964 4,611,420 4,898,007
IOU FEES (INCLUDING BILLING)19,548 60,794 287,618 584,729 660,114 745,569
OTHER A&G 191,261 189,204 249,729 302,806 373,125 398,084
SUBTOTAL A&G 1,567,259 1,528,720 4,746,946 6,731,802 7,469,659 8,035,535
(B) COST OF ENERGY 7,418,662 11,881,494 35,566,066 69,037,682 85,826,553 111,605,979
(C) DEBT SERVICE 654,595 394,777 747,729 1,195,162 1,195,162 1,151,494
TOTAL COST OF OPERATION 9,640,516 13,804,991 41,060,742 76,964,646 94,491,374 120,793,009
CCA PROGRAM SURPLUS/(DEFICIT)948,835 2,546,992 2,771,109 1,737,613 5,084,158 3,698,392
Marin Clean Energy
Summary of CCA Program Phase-In
(January 2010 through December 2015)
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CCA Program Working Capital (Phase 5)
MCE anticipates it will have sufficient internally generated funds to fund the Phase 5 customer
expansion. If additional funds are required, a short term credit agreement would be used to
support the expansion.
Renewable Resource Project Financing
MCE’s CCA Program may consider large project financings for renewable resources (likely
wind, solar, biomass or geothermal), which may total as much as $375 million (combined).
These financings would only occur after a sustained period of successful Program operation
and after appropriate project opportunities are identified and subjected to appropriate
environmental review. Such financing would likely occur after several successful years of
operating history have been observed and following MCE’s receipt of an institutional credit
rating. In the event that such financing becomes necessary, funds would include any short-term
financing for the renewable resource project development costs, and would extend over a 20- to
30-year term.
The security for such bonds would likely be a hybrid of the revenue from sales to the retail
customers of MCE, including a Termination Fee as described in Chapter 9, and the renewable
resource project itself.
The following table summarizes the potential financings in support of the CCA Program:
Proposed Financing Estimated Total
Amount
Estimated Term Estimated Issuance
Start-Up and Working
Capital
$2 million No longer than 7 years Early 2010
Working Capital Phase 3 $3 million No longer than 5 years Mid 2012
Potential Renewable
Resource Project Financings
$375 million
(aggregate)
20 to 30 years Undetermined
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CHAPTER 8 - Ratesetting and Program Terms and Conditions
Introduction
This Chapter describes MCE’s rate setting policies for electric aggregation services. These
include policies regarding rate design, objectives, and provision for due process in setting
Program rates. Program rates are ultimately approved by the Board. The Board would retain
authority to modify program policies from time to time at its discretion.
Rate Policies
MCE has established rates sufficient to recover all costs related to operation of the program,
including any reserves that may be required as a condition of financing and other discretionary
reserve funds that may be approved by the Board of Directors. As a general policy, rates will be
uniform for all similarly situated customers enrolled in the Program throughout the service area
of MCE, comprised of the jurisdictional boundaries of its members.
The primary objectives of the ratesetting plan are to set rates that achieve the following:
100 percent renewable energy supply option – Deep Green Tariff;
100 percent local solar energy supply option – Sol Shares Tariff
Rate competitive tariff option – Light Green Tariff (at 50 percent renewable energy);
Rate stability;
Equity among customers in each tariff;
Customer understanding; and
Revenue sufficiency.
Each of these objectives is described below.
Rate Competitiveness
The goal is to offer competitive rates for the electric services MCE provides to participating
customers. For Deep Green participants, the goal is to offer the lowest possible customer rates
with an incremental monthly cost premium of approximately 10 percent. For Sol Shares
customers, the goal is to offer rates that are generally reflective of local, small utility scale solar
development costs, which will initially relate to prices paid under MCE’s Feed-In Tariff.
Competitive rates will be critical to attracting and retaining key customers. As discussed above,
the principal long-term Program goal is to achieve 100 percent renewable energy supply subject
to economic and operating constraints. As previously discussed, the Program will significantly
increase renewable energy supply to Program customers, relative to the incumbent utility, by
offering two distinct rate tariffs. The default tariff for Program customers will be the Light
Green service option, which will maximize renewable energy supply (minimum 50 percent)
while maintaining competitive generation rates to those currently offered by PG&E. MCE will
also offer its customers a voluntary Deep Green Tariff, which will supply participating
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customers with 100 percent renewable energy supply at rates that reflect the Program’s cost for
procuring necessary energy supplies. As previously noted, MCE will be offering a third service
option, Sol Shares, which is planned to begin serving customers during the 2015 calendar year.
The voluntary Sol Shares service option will supply participating customers with 100 percent
locally generated solar electricity – MCE is currently accepting enrollments in the Sol Shares
program.
As previously suggested, the default tariff for Program customers will be the Light Green Tariff.
Consistent with this MCE policy, participating qualified low- or fixed-income households, such
as those currently enrolled in the California Alternate Rates for Energy (CARE) program, will be
automatically enrolled in the Light Green Tariff and will continue to receive related discounts
on monthly electricity bills. Based on projected participation in each tariff, the amount of
renewable energy supplied to Program customers as a percentage of the Program’s total energy
requirements is projected to approximate 52 percent in 2015.
Rate Stability
MCE will offer stable rates by hedging its supply costs over multiple time horizons. Rate
stability considerations may mean that program rates relative to PG&E’s may differ at any point
in time from the general rate targets set for the Program. Although MCE’s rates will be
stabilized through execution of appropriate price hedging strategies, the distribution utility’s
rates can fluctuate significantly from year-to-year based on energy market conditions such as
natural gas prices, the utilities’ hedging strategies, and hydro-electric conditions; and from rate
impacts caused by periodic additions of generation to utility rate base. MCE will have more
flexibility in procurement and ratesetting than PG&E to stabilize electricity costs for customers.
Equity among Customer Classes
MCE’s policy will be to provide rate benefits to all customer classes relative to the rates that
would otherwise be paid to the local distribution utility. Rate differences among customer
classes will reflect the rates charged by the local distribution utility as well as differences in the
costs of providing service to each class. Rate benefits may also vary among customers within
the major customer class categories, depending upon the specific rate designs adopted by the
Board of Directors.
Customer Understanding
The goal of customer understanding involves rate designs that are relatively straightforward so
that customers can readily understand how their bills are calculated. This not only minimizes
customer confusion and dissatisfaction but will also result in fewer billing inquiries to MCE’s
customer service call center. Customer understanding also requires rate structures to make
sense (i.e., there should not be differences in rates that are not justified by costs or by other
policies such as providing incentives for conservation).
Revenue Sufficiency
MCE’s rates must collect sufficient revenue from participating customers to fully fund MCE’s
annual budget. Rates will be set to collect the adopted budget based on a forecast of electric
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sales for the budget year. Rates will be adjusted as necessary to maintain the ability to fully
recover all of MCE’s costs, subject to the disclosure and due process policies described later in
this chapter.
Rate Design
MCE will generally match the rate structures from the utilities’ standard rates to avoid the
possibility that customers would see significantly different bill impacts as a result of changes in
rate structures when beginning service in MCE’s program. MCE may also introduce new rate
options for customers, such as rates designed to encourage economic expansion or business
retention within MCE’s service area.
Net Energy Metering
Customers with on-site generation eligible for net metering from PG&E will be offered a net
energy metering rate from MCE. Net energy metering allows for customers with certain
qualified solar or wind distributed generation to be billed on the basis of their net energy
consumption. The PG&E net metering tariff (E-NEM) requires the CCA to offer a net energy
metering tariff in order for the customer to continue to be eligible for service on Schedule E-
NEM. The objective is that MCE’s net energy metering tariff will apply to the generation
component of the bill, and the PG&E net energy metering tariff will apply to the utility’s
portion of the bill. MCE will pay customers for excess power produced from net energy
metered generation systems in accordance with the rate designs adopted by the MCE Board.
Disclosure and Due Process in Setting Rates and Allocating Costs among Participants
The Executive Officer, with support of appropriate staff, advisors and committees, will prepare
an annual budget and corresponding customer rates and submit these as an application for a
change in rates to the Board of Directors. The rates will be approved at a public meeting of the
Board of Directors no sooner than thirty one (31) days following public posting of the proposed
rates (which shall occur on MCE’s website) - during this thirty one-day review period, affected
customers will be able to provide comment on the proposed rate changes.
MCE will initially adopt customer noticing requirements similar to those the CPUC requires of
PG&E. These notice requirements are described as follows:
Notice of rate changes will be published at least once in a newspaper of general circulation
within the respective jurisdictions of MCE’s Member Agencies. This notice will be published
within ten days of MCE’s public posting of the subject rate change. Such notice will state that a
copy of said application and related exhibits may be examined at the offices of MCE and shall
include the locations of such offices
MCE will furnish notice of its application to its customers affected by the proposed increase,
either by including such notice as an on-bill message with the regular bill for charges
transmitted to such customers or by mailing such notice postage prepaid to such customers.
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The notice will state the amount of the proposed increase expressed in percentage terms, a brief
statement of the reasons the increase is required or sought, and the mailing address of MCE to
which any customer inquiries relative to the proposed increase, including a request by the
customer to receive notice of the date, time, and place of any hearing on the application, may be
directed.
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CHAPTER 9 – Customer Rights and Responsibilities
This chapter discusses customer rights, including the right to opt-out of the CCA Program and
the right to privacy of customer energy usage information, as well as obligations customers
undertake upon agreement to enroll in the CCA Program. All customers that do not opt out
within 30 days of the fourth opt-out notice will have agreed to become full status program
participants and must adhere to the obligations set forth below, as may be modified and
expanded by the MCE Board from time to time.
By adopting this Implementation Plan, the MCE Board approved the customer rights and
responsibilities policies contained herein to be effective at Program initiation. The Board retains
authority to modify program policies from time to time at its discretion.
Customer Notices
As part of the customer enrollment process, at least four notices will be provided to customers
describing the Program, informing them of their opt-out rights to remain with utility bundled
generation service, and containing a simple mechanism for exercising their opt-out rights. MCE
will mail at least two written notices to customers, beginning at least two calendar months, or
sixty days, in advance of the date of commencing automatic enrollment. MCE will likely use its
own mailing service for requisite opt-out notices rather than including the notices in PG&E’s
monthly bills. This is intended to increase the likelihood that customers will read the opt-out
notices, which may otherwise be ignored if included as a bill insert. Customers may opt out by
notifying MCE using MCE’s designated, telephone-based opt out processing service. Should
customers choose to initiate an opt-out request by contacting PG&E, they will be transferred to
MCE’s call center to complete the opt-out request. Consistent with CPUC regulations, notices
returned as undelivered mail would be treated as a failure to opt out, and the customer would
be automatically enrolled.
Following automatic enrollment, at least two notices will be mailed to customers within the first
two calendar months, or sixty days, of service. Opt-out requests made on or before the sixtieth
day following start of MCE service would result in customer transfer to bundled utility service
with no penalty. Such customers will be obligated to pay MCE’s charges for electric services
provided during the time the customer took service from the Program, but will otherwise not be
subject to any penalty or transfer fee from MCE.
New customers who establish service within the Program service area will be automatically
enrolled in the Program. Such customers will be mailed two opt-out notices within two
calendar months, or sixty-days, of enrollment. MCE’s Board of Directors will have the authority
to implement entry fees for customers that initially opt out of the Program, but later decide to
participate. Entry fees, if deemed necessary, would help prevent potential gaming, particularly
by large customers, and aid in resource planning by providing additional control over the
Program’s customer base. Entry fees would not be practical to administer, nor would they be
necessary, for residential and other small customers.
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Termination Fee
Customers that are automatically enrolled in the Program can elect to transfer back to the
incumbent utility without penalty within the first two months of service. After this free opt-out
period, customers will be allowed to terminate their participation subject to payment of a
Termination Fee. The Termination Fee may apply to all Program customers that elect to return
to bundled utility service or elect to take “direct access” service from an energy services
provider. Program customers that relocate within the Program’s service territory would have
their CCA service continued at the new address. If a customer relocating to an address within
the Program service territory elected to cancel CCA service, the Termination Fee may apply.
Program customers that move out of the Program’s service territory would not be subject to the
Program’s Termination Fee.
The Termination Fee will consist of two parts: an Administrative Fee set to recover the costs of
processing the customer transfer and other administrative or termination costs and a Cost
Recovery Charge (“CRC”) that would apply in the event MCE is unable to recover the costs of
supply commitments attributable to the customer that is terminating service. PG&E will collect
the Administrative Fee from returning customers as part of the final bill to the customer from
the CCA Program and will collect the CRC as a lump sum or on a monthly basis pursuant to a
negotiated servicing agreement between MCE and PG&E.
The Administrative Fee would vary by customer class as set forth in the table below.
Administrative Fee for Service Termination
Customer Class Fee
Residential $5
Non-Residential $25
The customer CRC will be equal to a pro rata share of any above market costs of MCE’s actual
or planned supply portfolio at the time the customer terminates service. The proposed CRC is
similar in concept to the Cost Responsibility Surcharge charged by PG&E, and it is designed to
prevent shifting of costs to remaining Program customers. The CRC will be set on an annual
basis by MCE’s Governing Board as part of the annual ratemaking process. At this time, MCE’s
CRC is set to zero.
If customers terminate service, MCE anticipates it will re-market the excess supply and recover
all or the majority of its costs. Depending upon market conditions, the CRC may not be needed
for recovery of stranded costs. However, MCE’s ability to assess a Cost Recovery Charge, if
necessary, can be an important condition for obtaining financing for MCE’s power supply. The
low cost financing will, in turn, enable MCE to charge rates that are competitive with PG&E’s.
The Termination Fee will be clearly disclosed in the four opt-out notices sent to customers
during the sixty-day period before automatic enrollment and following commencement of
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service. The fee could be changed prospectively by MCE’s Board of Directors, subject to MCE’s
customer noticing requirements. As previously noted, customers that opt-out during the
statutorily mandated notification period will not pay the Termination Fee that may be imposed
by MCE.
Customers electing to terminate service after the initial notification period that provided them
with at least four opt-out notices would be transferred to PG&E on their next regularly
scheduled meter read date if the termination notice is received a minimum of fifteen days prior
to that date. Customers who voluntarily transfer back to PG&E after the initial notification
period that provided them with at least four opt-out notices would also be liable for the
nominal reentry fees imposed by PG&E as set forth in the applicable utility CCA tariffs. Such
customers would also be required to remain on bundled utility service for a period of one year,
as described in the utility tariffs.
Customer Confidentiality
MCE has established policies covering confidentiality of customer data. These policies are fully
compliant with the California Public Utility Commission’s required privacy protection rules for
CCA customer energy usage information detailed within Decision D.12-08-045. MCE’s policies
will maintain confidentiality of individual customer data. Confidential data includes individual
customers’ name, service address, billing address, telephone number, account number and
electricity consumption. Aggregate data may be released at MCE’s discretion or as required by
law or regulation.
Responsibility for Payment
Customers will be obligated to pay MCE charges for service provided through the date of
transfer including any applicable Termination Fees. Pursuant to current CPUC regulations,
MCE will not be able to direct that electricity service be shut off for failure to pay MCE’s bill.
However, PG&E has the right to shut off electricity to customers for failure to pay electricity
bills, and Rule 23 mandates that partial payments are to be allocated pro rata between PG&E
and the CCA. In most circumstances, customers would be returned to utility service for failure
to pay bills in full and customer deposits would be withheld in the case of unpaid bills. PG&E
would attempt to collect any outstanding balance from customers in accordance with Rule 23
and the related CCA Service Agreement. The proposed process is for two late payment notices
to be provided to the customer within 30 days of the original bill due date. If payment is not
received within 45 days from the original due date, service would be transferred to the utility
on the next regular meter read date, unless alternative payment arrangements have been made.
Consistent with the CCA tariffs, Rule 23, service cannot be discontinued to a residential
customer for a disputed amount if that customer has filed a complaint with the CPUC, and that
customer has paid the disputed amount into an escrow account.
Customer Deposits
Customers may be required to post a deposit equal to two months’ estimated bills for MCE’s
charges to obtain service from the Program. MCE has adopted a related policy, Rule No. 002,
which specifies the circumstances under which a customer deposit will be required. This policy
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specifies that “An applicant who previously has been a customer of PG&E or MCE and whose
electric service has been discontinued by PG&E or MCE during the last twelve months of that
prior service because of nonpayment of bills, may be required to reestablish credit by depositing
the amount prescribed in Rule 003 (Deposits) for that purpose.” Rule No. 002 also states that,
“A customer who fails to pay bills before they become past due as defined in PG&E Electric
Rule 11 (Discontinuance and Restoration of Service), and who further fails to pay such bills
within five days after presentation of a discontinuance of service notice for nonpayment of bills,
may be required to pay said bills and reestablish credit by depositing the amount prescribed in
Rule 003 (Deposits). This rule will apply regardless of whether or not service has been
discontinued for such nonpayment11.” Rule 003 specifies that the amount of deposit for such a
customer shall be equal to two months’ estimated charges for MCE service. Failure to post
deposit as required would cause the account service transfer request to be rejected, and the
account would remain with PG&E. To date, MCE has not collected any customer deposits.
11 A customer whose service is discontinued by MCE is returned to PG&E generation service.
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CHAPTER 10 - Procurement Process
Introduction
This Chapter describes MCE’s initial procurement policies and the key third party service
agreements by which MCE has obtained operational services for the CCA Program. By
adopting the original Implementation Plan, MCE’s Board of Directors approved general
procurement policies to be effective at Program initiation. The Board retains authority to
modify Program policies from time to time at its discretion.
Procurement Methods
MCE has entered into agreements for a variety of services needed to support program
development, operation and management. It is anticipated MCE will utilize Competitive
Procurement, Direct Procurement or Sole Source Procurement, depending on the nature of the
services to be procured. Direct Procurement is the purchase of goods or services without
competition when multiple sources of supply are available. Sole Source Procurement is
generally to be performed only in the case of emergency or when a competitive process would
be an idle act.
MCE utilized a competitive solicitation process to enter into agreements with SENA, which
provides electrical services for the program. Agreements with entities that provide professional
legal or consulting services, and agreements pertaining to unique or time sensitive
opportunities, may be entered into on a direct procurement or sole source basis at the discretion
of MCE’s Executive Officer or Board of Directors.
The Executive Officer periodically reports (e.g., quarterly) to the Board a summary of the
actions taken with respect to the delegated procurement authority.
Authority for terminating agreements will generally mirror the authority for entering into the
agreements.
Key Contracts
Electric Supply Contract
MCE successfully negotiated an electricity supply contract with SENA (through December 31,
2016). For the initial years of program operations (, SENA will supply a significant portion of
the electricity delivered to MCE customers. For the post-2016 period, MCE will be obligated to
complete additional solicitations to secure its resource requirements. In anticipation of this
future obligation, MCE has initiated procurement efforts, focusing on necessary renewable
energy supply and resource adequacy capacity, to facilitate the transition from full
requirements service to a managed portfolio of contracts/resources. This proactive, ongoing
approach will avoid dependence on market conditions existing at any single point in time.
Under the initial full requirements contract, SENA has committed to serving the composite
electrical loads of customers in the Program. SENA also serves as MCE’s certified Scheduling
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Coordinator and will schedule the loads of all customers in the Program, providing necessary
electric energy, capacity/resource adequacy requirements, renewable energy and ancillary
services. SENA is wholly responsible for the Program’s portfolio operations functions and
managing the predominant supply risks for the term of the contract. SENA must also meet the
Program’s renewable energy goals and comply with all applicable resource adequacy and
regulatory requirements imposed by the CPUC or FERC.
Certain financial risks related to changes in Program loads during the term of the agreement are
borne by SENA, within the ranges specified in the electric supply agreement. The supplier has
also committed to deliver a specific quantity of RPS-eligible renewable energy, as determined
by MCE, during each year of the agreement term. The supplier is also required to procure
sufficient renewable energy to meet the requirements of serving customers enrolled in the Deep
Green MCE service option.
Data Management Contract
Noble Americas Energy Solutions will provide the retail customer services of billing and other
customer account services (electronic data interchange or EDI with PG&E, billing, remittance
processing, and account management). Recognizing that some qualified wholesale energy
suppliers do not typically conduct retail customer services whereas others (i.e., direct access
providers) do, the data management contract is separate from the electric supply contract...12
The data manager is responsible for the following services:
Data exchange with PG&E;
Technical testing;
Customer information system;
Customer call center;
Billing administration/retail settlements; and
Reporting and audits of utility billing.
Utilizing a third party for account services eliminates a significant expense associated with
implementing a customer information system. Such systems can cost from five to ten million
dollars to implement and take significant time to deploy. A longer term contract is appropriate
for this service because of the time and expense that would be required to migrate data to a new
system. Separation of the data management contract from the energy supply contract gives
MCE greater flexibility to change energy suppliers, if desired, without facing an expensive data
migration issue.
12 The contractor performing account services may be the same entity as the contractor supplying electricity for the
program.
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Electric Supply Procurement Process
As previously noted, MCE selected SENA as its energy supplier through a competitive
solicitation process, which was administered in mid-2009. Additional information regarding
SENA is provided below.
Shell Energy North America
Shell Energy North America (US), L.P. (SENA) is a leading supplier of energy and associated
services in North America. SENA provides natural gas, electrical energy and capacity,
scheduling and asset optimization, risk management, and renewable energy and environmental
products to a wide variety of customers. SENA is 100% owned by Royal Dutch Shell Company
and its subsidiaries. SENA owns and manages a variety of energy assets in the West, including
generation, a portfolio of renewable energy, transmission capacity, natural gas production,
liquefied natural gas capacity, natural gas storage capacity, and natural gas pipeline capacity.
SENA’s West Region operation includes regional offices in San Diego, Portland, Spokane,
Berkeley, Salt Lake City, Denver and Mexico City, with 7 X 24 power and gas operations in San
Diego and Spokane.
SENA has an extensive list of public and privately owned customers in the West, including all
WECC region investor-owned utilities, twenty-five publicly owned (municipal) electric
utilities/other public agencies in California, and publicly owned utilities/public agencies in
neighboring states. SENA’s West Region full requirements power experience includes
provision of retail electric service, including provision of resource adequacy, for direct access
customers in California.
Renewable energy products offered by SENA include renewable energy, bundled renewable
energy, landfill gas, biogas and renewable energy credits. SENA states it is actively developing
renewable portfolios and provides related services such as scheduling and shaping of
intermittent energy. SENA’s affiliate, Shell WindEnergy, develops and owns wind generation
in California and other parts of North America. SENA also offers a variety of environmental
products including emission offsets and other carbon reducing products.
SENA is rated A- by S&P and A2 by Moody’s.
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CHAPTER 11 – Contingency Plan for Program Termination
Introduction
This Chapter describes the process to be followed in the case of Program termination. By
adopting the original Implementation Plan, MCE’s Board of Directors approved the general
termination process contained herein to be effective at Program initiation. In the unexpected
event that MCE would terminate the Program and return its customers to PG&E service, the
proposed process is designed to minimize the impacts on its customers and on PG&E. The
proposed termination plan follows the requirements set forth in PG&E’s tariff Rule 23
governing service to CCAs. The Board retains authority to modify program policies from time
to time at its discretion.
Termination by Marin Clean Energy
MCE will offer services for the long term with no planned Program termination date. In the
unanticipated event that the majority of the Member’s governing bodies (County Board of
Supervisors and/or City/Town Councils) decide to terminate the Program, each governing body
would be required to adopt a termination ordinance or resolution and provide adequate notice
to MCE consistent with the terms set forth in the JPA Agreement. Following such notice, MCE
would vote on Program termination subject to a two-tiered vote, as described in the JPA
Agreement. In the event that the Board affirmatively votes to proceed with JPA termination,
the Board would disband under the provisions identified in its JPA Agreement.
After any applicable restrictions on such termination have been satisfied, notice would be
provided to customers six months in advance that they will be transferred back to PG&E. A
second notice would be provided during the final sixty-days in advance of the transfer. The
notice would describe the applicable distribution utility bundled service requirements for
returning customers then in effect, such as any transitional or bundled portfolio service rules.
At least one year advance notice would be provided to PG&E and the CPUC before transferring
customers, and MCE would coordinate the customer transfer process to minimize impacts on
customers and ensure no disruption in service. Once the customer notice period is complete,
customers would be transferred en masse on the date of their regularly scheduled meter read
date.
MCE will post a bond or maintain funds held in reserve to pay for potential transaction fees
charged to the Program for switching customers back to distribution utility service. Reserves
would be maintained against the fees imposed for processing customer transfers (CCASRs).
The Public Utilities Code requires demonstration of insurance or posting of a bond sufficient to
cover reentry fees imposed on customers that are involuntarily returned to distribution utility
service under certain circumstances. The cost of reentry fees are the responsibility of the energy
services provider or the community choice aggregator, except in the case of a customer returned
for default or because its contract has expired. MCE will post financial security in the
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appropriate amount as part of its registration materials and will maintain the financial security
in the required amount, as necessary.
Termination by Members
The JPA Agreement defines the terms and conditions under which Members may terminate
their participation in the program.
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CHAPTER 12 – Appendices
Appendix A: MCE Resolution 2014-03
Appendix B: County of Napa, Resolution 2014-59
Appendix C: Marin Clean Energy Joint Powers Agreement
Appendix D: County of Napa, CCA Ordinance – Ordinance No. 1391
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27 April 2016 – Addendum No. 4
Exhibit A
To the
Joint Powers Agreement
Marin Energy Authority
-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.)
“Administrative Services Agreement” means an agreement or agreements entered
into after the Effective Date by the Authority with an entity that will perform tasks
necessary for planning, implementing, operating and administering the CCA Program or
any other energy programs adopted by the Authority.
“Agreement” means this Joint Powers Agreement.
“Annual Energy Use” has the meaning given in Section 4.9.2.2.
“Authority” means the Marin 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.
“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 Marin 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
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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 one or more Administrative Services Provider
Agreements and Program Agreement 1. Administrative and operational costs incurred
after the approval of Program Agreement 1 shall not be considered Initial Costs.
“Initial Participants” means, for the purpose of this Agreement, the signatories to this
JPA as of May 5, 2010 including City of Belvedere, Town of Fairfax, City of Mill Valley,
Town of San Anselmo, City of San Rafael, City of Sausalito, Town of Tiburon and County of
Marin.
“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 3.2 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 3.2 such that it is considered a member of the Authority.
“Program Agreement 1” means the agreement that the Authority will enter into
with an energy service provider that will provide the electricity to be distributed to
customers participating in the CCA Program.
“Total Annual Energy” has the meaning given in Section 4.9.2.2.
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Exhibit B
To the
Joint Powers Agreement
Marin Energy Authority
-List of the Parties-
City of American Canyon
City of Belvedere
City of Benicia
City of Calistoga
Town of Corte Madera
City of El Cerrito
Town of Fairfax
City of Larkspur
City of Lafayette
City of Mill Valley
City of Napa
City of Novato
City of Richmond
Town of Ross
Town of San Anselmo
City of San Pablo
City of San Rafael
City of Sausalito
City of St. Helena
Town of Tiburon
City of Walnut Creek
Town of Yountville
County of Marin
County of Napa
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30 April 2016 – Addendum No. 4
Exhibit C
To the
Joint Powers Agreement
Marin Clean Energy
- Annual Energy Use -
This Exhibit C is effective as of April 21, 2016.
Party kWh*
City of American Canyon 83,543,443
City of Belvedere 9,973,170
City of Benicia 272,731,094
City of Calistoga 27,989,218
Town of Corte Madera 62,093,107
City of El Cerrito 109,836,169
Town of Fairfax 24,700,647
City of Lafayette 126,334,082
City of Larkspur 63,174,199
City of Mill Valley 69,176,164
City of Napa 386,262,547
City of Novato 286,565,119
City of Richmond 581,012,267
Town of Ross 13,529,793
Town of San Anselmo 46,642,417
City of San Pablo 97,383,170
City of San Rafael 347,362,327
City of Sausalito 48,099,763
City of St. Helena 55,556,737
Town of Tiburon 40,913,144
City of Walnut Creek 465,644,787
Town of Yountville 34,502,172
County of Marin 330,023,521
County of Napa 348,095,521
Authority Total Energy Use 3,931,144,578
*Data Provided by PG&E
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31 April 2016 – Addendum No. 4
Exhibit D
To the
Joint Powers Agreement
Marin Clean Energy
- Voting Shares -
This Exhibit D is effective as of April 21, 2016.
Party kWh* Section 4.9.2.1 Section 4.9.2.2 Voting Share
City of American Canyon 83,543,443 2.08% 1.06% 3.15%
City of Belvedere 9,973,170 2.08% 0.13% 2.21%
City of Benicia 272,731,094 2.08% 3.47% 5.55%
City of Calistoga 27,989,218 2.08% 0.36% 2.44%
Town of Corte Madera 62,093,107 2.08% 0.79% 2.87%
City of El Cerrito 109,836,169 2.08% 1.40% 3.48%
Town of Fairfax 24,700,647 2.08% 0.31% 2.40%
City of Lafayette 126,334,082 2.08% 1.61% 3.69%
City of Larkspur 63,174,199 2.08% 0.80% 2.89%
City of Mill Valley 69,176,164 2.08% 0.88% 2.96%
City of Napa 386,262,547 2.08% 4.91% 7.00%
City of Novato 286,565,119 2.08% 3.64% 5.73%
City of Richmond 581,012,267 2.08% 7.39% 9.47%
Town of Ross 13,529,793 2.08% 0.17% 2.26%
Town of San Anselmo 46,642,417 2.08% 0.59% 2.68%
City of San Pablo 97,383,170 2.08% 1.24% 3.32%
City of San Rafael 347,362,327 2.08% 4.42% 6.50%
City of Sausalito 48,099,763 2.08% 0.61% 2.70%
City of St. Helena 55,556,737 2.08% 0.71% 2.79%
Town of Tiburon 40,913,144 2.08% 0.52% 2.60%
City of Walnut Creek 465,644,787 2.08% 5.92% 8.01%
Town of Yountville 34,502,172 2.08% 0.44% 2.52%
County of Marin 330,023,521 2.08% 4.20% 6.28%
County of Napa 348,095,521 2.08% 4.43% 6.51%
*Data Provided by PG&E 3,931,144,578 50.00% 50.00% 100.00%
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383
384
385
386
387
388
389
390
391
392
393
394
395
396
October 4, 2016 County Approval Agreement
East Bay Community Energy Authority
- Joint Powers Agreement –
Effective _____________
Among The Following Parties:
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EAST BAY COMMUNITY 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 A (“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. In 2006, the State Legislature adopted AB 32, the Global Warming Solutions Act, which
mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels. The California
Air Resources Board is promulgating regulations to implement AB 32 which will require
local government to develop programs to reduce greenhouse gas emissions.
3. The purposes for the Initial Participants (as such term is defined in Section 1.1.16 below)
entering into this Agreement include securing electrical energy supply for customers in
participating jurisdictions, addressing climate change by reducing energy related
greenhouse gas emissions, promoting electrical rate price stability, and fostering local
economic benefits such as jobs creation, community energy programs and local power
development. 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 State, regional and local solar and wind energy production.
4. The Parties desire to establish a separate public agency, known as the East Bay
Community 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.
5. 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.
6. By establishing the Authority, the Parties seek to:
(a) Provide electricity rates that are lower or competitive with those offered by PG&E for
similar products;
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(b) Offer differentiated energy options (e.g. 33% or 50% qualified renewable) for default
service, and a 100% renewable content option in which customers may “opt-up” and
voluntarily participate;
(c) Develop an electric supply portfolio with a lower greenhouse gas (GHG) intensity
than PG&E, and one that supports the achievement of the parties’ greenhouse gas
reduction goals and the comparable goals of all participating jurisdictions;
(d) Establish an energy portfolio that prioritizes the use and development of local
renewable resources and minimizes the use of unbundled renewable energy credits;
(e) Promote an energy portfolio that incorporates energy efficiency and demand response
programs and has aggressive reduced consumption goals;
(f) Demonstrate quantifiable economic benefits to the region (e.g. union and prevailing
wage jobs, local workforce development, new energy programs, and increased local
energy investments);
(g) Recognize the value of workers in existing jobs that support the energy infrastructure
of Alameda County and Northern California. The Authority, as a leader in the shift to
a clean energy, commits to ensuring it will take steps to minimize any adverse
impacts to these workers to ensure a “just transition” to the new clean energy
economy;
(h) Deliver clean energy programs and projects using a stable, skilled workforce through
such mechanisms as project labor agreements, or other workforce programs that are
cost effective, designed to avoid work stoppages, and ensure quality;
(i) Promote personal and community ownership of renewable resources, spurring
equitable economic development and increased resilience, especially in low income
communities;
(j) Provide and manage lower cost energy supplies in a manner that provides cost
savings to low-income households and promotes public health in areas impacted by
energy production; and
(k) Create an administering agency that is financially sustainable, responsive to regional
priorities, well managed, and a leader in fair and equitable treatment of employees
through adopting appropriate best practices employment policies, including, but not
limited to, promoting efficient consideration of petitions to unionize, and providing
appropriate wages and benefits.
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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 below, unless the context requires otherwise.
1.1.1 “AB 117” means Assembly Bill 117 (Stat. 2002, ch. 838, codified at
Public Utilities Code Section 366.2), which created CCA.
1.1.2 “Act” means the Joint Exercise of Powers Act of the State of California
(Government Code Section 6500 et seq.)
1.1.3 “Agreement” means this Joint Powers Agreement.
1.1.4 “Annual Energy Use” has the meaning given in Section 1.1.23.
1.1.5 “Authority” means the East Bay Community Energy Authority established
pursuant to this Joint Powers Agreement.
1.1.6 “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.
1.1.7 “Board” means the Board of Directors of the Authority.
1.1.8 “Community Choice Aggregation” or “CCA” means an electric service
option available to cities and counties pursuant to Public Utilities Code
Section 366.2.
1.1.9 “CCA Program” means the Authority’s program relating to CCA that is
principally described in Sections 2.4 and 5.1.
1.1.10 “Days” shall mean calendar days unless otherwise specified by this
Agreement.
1.1.11 “Director” means a member of the Board of Directors representing a
Party, including an alternate Director.
1.1.12 “Effective Date” means the date on which this Agreement shall become
effective and the East Bay Community Energy Authority shall exist as a
separate public agency, as further described in Section 2.1.
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1.1.13 “Ex Officio Board Member” means a non-voting member of the Board of
Directors as described in Section 4.2.2. The Ex Officio Board Member
may not serve on the Executive Committee of the Board or participate in
closed session meetings of the Board.
1.1.14 “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.
1.1.15 “Initial Costs” means all costs incurred by the Authority relating to the
establishment and initial operation of the Authority, such as the hiring of a
Chief Executive Officer and any administrative staff, any required
accounting, administrative, technical and legal services in support of the
Authority’s initial formation activities or in support of the negotiation,
preparation and approval of power purchase agreements. The Board shall
determine the termination date for Initial Costs.
1.1.16 “Initial Participants” means, for the purpose of this Agreement the County
of Alameda, the Cities of Albany, Berkeley, Emeryville, Oakland,
Piedmont, San Leandro, Hayward, Union City, Newark, Fremont, Dublin,
Pleasanton and Livermore.
1.1.17 “Operating Rules and Regulations” means the rules, regulations, policies,
bylaws and procedures governing the operation of the Authority.
1.1.18 “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.
1.1.19 “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.
1.1.20 “Percentage Vote” means a vote taken by the Board pursuant to Section
4.12.1 that is based on each Party having one equal vote.
1.1.21 “Total Annual Energy” has the meaning given in Section 1.1.23.
1.1.22 “Voting Shares Vote” means a vote taken by the Board pursuant to
Section 4.12.2 that is based on the voting shares of each Party described in
Section 1.1.23 and set forth in Exhibit C to this Agreement. A Voting
Shares vote cannot take place on a matter unless the matter first receives
an affirmative or tie Percentage Vote in the manner required by Section
4.12.1 and three or more Directors immediately thereafter request such
vote.
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1.1.23 “Voting Shares Formula” means the weight applied to a Voting Shares
Vote and is determined by the following formula:
(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 B and
the initial voting shares are designated in Exhibit C. Both Exhibits B and
C 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.
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: List of the Parties
Exhibit B: Annual Energy Use
Exhibit C: Voting Shares
1.3 Revision of Exhibits. The Parties agree that Exhibits A, B and C 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 EAST BAY COMMUNITY ENERGY AUTHORITY
2.1 Effective Date and Term. This Agreement shall become effective and East Bay
Community Energy Authority shall exist as a separate public agency on December 1, 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 7.3, subject to the rights of the Parties to withdraw from
the Authority.
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2.2 Initial Participants. Until December 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
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
East Bay Community 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 participate as a group in the CCA Program pursuant to Public
Utilities Code Section 366.2(c)(12); 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.
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 to make and enter into contracts, including those relating to the purchase
or sale of electrical energy or attributes thereof;
2.5.2 to employ agents and employees, including but not limited to a Chief
Executive Officer and General Counsel;
2.5.3 to acquire, contract, manage, maintain, and operate any buildings, works
or improvements, including electric generating facilities;
2.5.4 to 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 to lease any property;
2.5.6 to sue and be sued in its own name;
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2.5.7 to 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;
2.5.8 to form subsidiary or independent corporations or entities, if appropriate,
to carry out energy supply and energy conservation programs at the lowest
possible cost consistent with the Authority’s CCA Program
implementation plan, risk management policies, or to take advantage of
legislative or regulatory changes;
2.5.9 to issue revenue bonds and other forms of indebtedness;
2.5.10 to apply for, accept, and receive all licenses, permits, grants, loans or other
assistance from any federal, state or local public agency;
2.5.11 to 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;
2.5.12 to adopt rules, regulations, policies, bylaws and procedures governing the
operation of the Authority (“Operating Rules and Regulations”);
2.5.13 to 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; and
2.5.14 to negotiate project labor agreements, community benefits agreements and
collective bargaining agreements with the local building trades council
and other interested parties.
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 Emeryville 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 and comply with the California
Environmental Quality Act (“CEQA”).
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2.8 Compliance with the Brown Act. The Authority and its officers and employees
shall comply with the provisions of the Ralph M. Brown Act, Government Code Section 54950
et seq.
2.9 Compliance with the Political Reform Act and Government Code Section
1090. The Authority and its officers and employees shall comply with the Political Reform Act
(Government Code Section 81000 et seq.) and Government Code Section 1090 et seq, and shall
adopt a Conflict of Interest Code pursuant to Government Code Section 87300. The Board of
Directors may adopt additional conflict of interest regulations in the Operating Rules and
Regulations.
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 an affirmative vote of a majority of all Directors of the entire
Board satisfying the requirements described in Section 4.12, 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.
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 of Directors. The Directors shall be appointed 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
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from a Board meeting. The person appointed and designated as the
regular Director shall be a member of the governing body of the Party.
The person appointed and designated as the alternate Director shall also be
a member of the governing body of the Party.
4.2.2 The Board shall also include one non-voting ex officio member as defined
in Section 1.1.13 (“Ex Officio Board Member”). The Chair of the
Community Advisory Committee, as described in Section 4.9 below, shall
serve as the Ex Officio Board Member. The Vice Chair of the Community
Advisory Committee shall serve as an alternate Ex Officio Board Member
when the regular Ex Officio Board Member is absent from a Board
meeting.
4.2.3 The Operating Rules and Regulations, to be developed and approved by
the Board in accordance with Section 2.5.12 may include rules regarding
Directors, such as meeting attendance requirements. No Party shall be
deprived of its right to seat a Director on the Board.
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, except that less than a quorum may adjourn a meeting from time to time in accordance
with law.
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. Board approval
shall be required for any of the following actions, which are defined as “Essential Functions”:
4.5.1 The issuance of bonds or any other financing even if program revenues are
expected to pay for such financing.
4.5.2 The hiring of a Chief Executive Officer and General Counsel.
4.5.3 The appointment or removal of an officer.
4.5.4 The adoption of the Annual Budget.
4.5.5 The adoption of an ordinance.
4.5.6 The initiation of resolution of claims and litigation where the Authority
will be the defendant, plaintiff, petitioner, respondent, cross complainant
or cross petitioner, or intervenor; provided, however, that the Chief
Executive Officer or General Counsel, on behalf of the Authority, may
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intervene in, become party to, or file comments with respect to any
proceeding pending at the California Public Utilities Commission, the
Federal Energy Regulatory Commission, or any other administrative
agency, without approval of the Board. The Board shall adopt Operating
Rules and Regulations governing the Chief Executive Officer and General
Counsel’s exercise of authority under this Section 4.5.6.
4.5.7 The setting of rates for power sold by the Authority and the setting of
charges for any other category of service provided by the Authority.
4.5.8 Termination of the CCA Program.
4.6 Executive Committee. The Board shall 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 Board’s authority to delegate certain Essential Functions, as described in Section 4.5 and the
Operating Rules and Regulations. The Board may not delegate to the Executive Committee or
any other committee its authority under Section 2.5.12 to adopt and amend the Operating Rules
and Regulations or its Essential Functions listed in Section 4.5. After the Executive Committee
meets or otherwise takes action, it shall, as soon as practicable, make a report of its activities at a
meeting of the Board.
4.7 Director Compensation. Directors shall receive a stipend of $100 per meeting,
as adjusted to account for inflation, as provided for in the Authority’s Operating Rules and
Regulations.
4.8 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. The Board may establish rules, regulations, policies, bylaws or
procedures to govern any such commissions, boards, or committees and shall determine whether
members shall be compensated or entitled to reimbursement for expenses.
4.9 Community Advisory Committee. The Board shall establish a Community
Advisory Committee consisting of nine members, none of whom may be voting members of the
Board. The function of the Community Advisory Committee shall be to advise the Board of
Directors on all subjects related to the operation of the CCA Program as set forth in a work plan
adopted by the Board of Directors from time to time, with the exception of personnel and
litigation decisions. The Community Advisory Committee is advisory only, and shall not have
decision-making authority, or receive any delegation of authority from the Board of Directors.
The Board shall publicize the opportunity to serve on the Community Advisory Committee, and
shall appoint members of the Community Advisory Committee from those individuals
expressing interest in serving, and who represent a diverse cross-section of interests, skill sets
and geographic regions. Members of the Community Advisory Committee shall serve staggered
four-year terms (the first term of three of the members shall be two years, and four years
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thereafter), which may be renewed. A member of the Community Advisory Committee may be
removed by the Board of Directors by majority vote. The Board of Directors shall determine
whether the Community Advisory Committee members will receive a stipend and/or be entitled
to reimbursement for expenses.
4.10 Chief Executive Officer. The Board of Directors shall appoint a Chief Executive
Officer for the Authority, who shall be responsible for the day-to-day operation and management
of the Authority and the CCA Program. The Chief Executive Officer may exercise all powers of
the Authority, including the power to hire, discipline and terminate employees as well as the
power to approve any agreement, if the expenditure is authorized in the Authority’s approved
budget, except the powers specifically set forth in Section 4.5 or those powers which by law
must be exercised by the Board of Directors. The Board of Directors shall provide procedures
and guidelines for the Chief Executive Officer exercising the powers of the Authority in the
Operating Rules and Regulations.
4.11 General Counsel. The Board of Directors shall appoint a General Counsel for
the Authority, who shall be responsible for providing legal advice to the Board of Directors and
overseeing all legal work for the Authority.
4.12 Board Voting.
4.12.1 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 “Percentage Vote” as defined in Section
1.1.20). A supermajority vote is required by this Agreement for the
matters addressed by Section 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 Percentage Vote of the specified
supermajority of all Directors on the entire Board. No action can be taken
by the Board without an affirmative Percentage Vote. Notwithstanding
the foregoing, in the event of a tie in the Percentage Vote, an action may
be approved by an affirmative “Voting Shares Vote,” as defined in Section
1.1.22, if three or more Directors immediately request such vote.
4.12.2 Voting Shares Vote. In addition to and immediately after an affirmative
percentage vote, three or more Directors may request that, a vote of the
voting shares shall be held (a “Voting Shares Vote” as defined in Section
1.1.22). To approve an action by a Voting Shares Vote, the corresponding
voting shares (as defined in Section 1.1.23 and Exhibit C) of all Directors
voting in the affirmative shall exceed 50% of the voting share of all
Directors on the entire Board, or such other higher voting shares
percentage expressly required by this Agreement or the Operating Rules
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and Regulations. 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. Notwithstanding the
foregoing, in the event of a tie in the Percentage Vote, an action may be
approved on an affirmative Voting Shares Vote. When a supermajority
vote is required by this Agreement or the Operating Rules and
Regulations, the supermajority vote is subject to the Voting Share Vote
provisions of this Section 4.12.2, and the specified supermajority of all
Voting Shares is required for approval of the action, if the provision of this
Section 4.12.2 are triggered.
4.13 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
and Emergency meetings of the Board may be called in accordance with the provisions of
California Government Code Section 54956 and 54956.5. Directors may participate in meetings
telephonically, with full voting rights, only to the extent permitted by law.
4.14 Officers.
4.14.1 Chair and Vice Chair. At the first meeting held by the Board in each
calendar year, the Directors shall elect, 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 Chair and Vice Chair
shall hold office for one year and serve no more than two consecutive
terms, however, the total number of terms a Director may serve as Chair
or Vice Chair is not limited. The office of either the Chair or Vice Chair
shall be declared vacant and the Board shall make a new selection if: (a)
the person serving dies, resigns, or ceases to be a member of the governing
body of the Party that the person represents; (b) the Party that the person
represents removes the person as its representative on the Board, or (c) the
Party that he or she represents withdraws from the Authority pursuant to
the provisions of this Agreement.
4.14.2 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.
4.14.3 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. The same person may not
simultaneously hold both the office of Treasurer and the office of the
Auditor of the Authority. Unless otherwise exempted from such
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requirement, the Authority shall cause an independent audit to be made
annually 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.
4.15 Administrative Services Provider. The Board may appoint one or more
administrative services providers to serve as the Authority’s agent for planning, implementing,
operating and administering the CCA Program, and any other program approved by the Board, in
accordance with the provisions of an Administrative Services Agreement. The appointed
administrative services provider may be one of the Parties. The Administrative Services
Agreement shall set forth the terms and conditions by which the appointed administrative
services provider shall perform or cause to be performed all tasks necessary for planning,
implementing, operating and administering the CCA Program and other approved programs.
The Administrative Services Agreement shall set forth the term of the Agreement and the
circumstances under which the Administrative Services Agreement may be terminated by the
Authority. This section shall not in any way be construed to limit the discretion of the Authority
to hire its own employees to administer the CCA Program or any other program.
4.16 Operational Audit. The Authority shall commission an independent agent to
conduct and deliver at a public meeting of the Board an evaluation of the performance of the
CCA Program relative to goals for renewable energy and carbon reductions. The Authority shall
approve a budget for such evaluation and shall hire a firm or individual that has no other direct or
indirect business relationship with the Authority. The evaluation shall be conducted at least once
every two years.
ARTICLE 5
IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS
5.1 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.
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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 4.12.
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 Other Authority Documents. The Parties acknowledge and agree that the
operations 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.
5.3 Integrated Resource Plan. The Authority shall cause to be prepared an
Integrated Resource Plan in accordance with CPUC regulations that will ensure the long-term
development and administration of a variety of energy programs that promote local renewable
resources, conservation, demand response, and energy efficiency, while maintaining compliance
with the State Renewable Portfolio standard and customer rate competitiveness. The Authority
shall prioritize the development of energy projects in Alameda and adjacent counties. Principal
aspects of its planned operations shall be in a Business Plan as outlined in Section 5.4 of this
Agreement.
5.4 Business Plan. The Authority shall cause to be prepared a Business Plan, which
will include a roadmap for the development, procurement, and integration of local renewable
energy resources as outlined in Section 5.3 of this Agreement. The Business Plan shall include a
description of how the CCA Program will contribute to fostering local economic benefits, such
as job creation and community energy programs. The Business Plan shall identify opportunities
for local power development and how the CCA Program can achieve the goals outlined in
Recitals 3 and 6 of this Agreement. The Business Plan shall include specific language detailing
employment and labor standards that relate to the execution of the CCA Program as referenced
in this Agreement. The Business Plan shall identify clear and transparent marketing practices to
be followed by the CCA Program, including the identification of the sources of its electricity and
explanation of the various types of electricity procured by the Authority. The Business Plan
shall cover the first five (5) years of the operation of the CCA Program. The Business Plan shall
be completed by the Authority no later than eight (8) months after the seating of the Authority
Board of Directors. Progress on the implementation of the Business Plan shall be subject to
annual public review.
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5.5 Labor Organization Neutrality. The Authority shall remain neutral in the event
its employees, and the employees of its subcontractors, if any, wish to unionize.
5.6 Renewable Portfolio Standards. The Authority shall provide its customers
energy primarily from Category 1 eligible renewable resources, as defined under the California
RPS and consistent with the goals of the CCA Program. The Authority shall not procure energy
from Category 3 eligible renewable resources (unbundled Renewable Energy Credits or RECs)
exceeding 50% of the State law requirements, to achieve its renewable portfolio goals.
However, for Category 3 RECs associated with generation facilities located within its service
jurisdiction, the limitation set forth in the preceding sentence shall not apply.
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.
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 County shall fund the Initial Costs of
establishing and implementing the CCA Program. In the event that the
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CCA Program becomes operational, these Initial Costs paid by the County
and any specified interest shall be included in the customer charges for
electric services to the extent permitted by law, and the County shall be
reimbursed from the payment of such charges by customers of the
Authority. The Authority may establish a reasonable time period over
which such costs are recovered. In the event that the CCA Program does
not become operational, the County shall not be entitled to any
reimbursement of the Initial Costs.
6.3.4 Additional Contributions and Advances. Pursuant to Government Code
Section 6504, the Parties may in their sole 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.
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.
Withdrawal of a Party shall require an affirmative vote of the Party’s
governing board.
7.1.2 Withdrawal Following 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.
7.1.3 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 estimated
renewable energy to be used with that of the incumbent utility. Within 30
days after receiving this report, through its City Manager or a person
expressly authorized by the Party, any Party may immediately withdraw
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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 qualified renewable
energy than the incumbent utility. Any Party who withdraws from the
Authority pursuant to this Section 7.1.3 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
7.3. 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.
7.2 Continuing Liability After Withdrawal; Further Assurances; Refund. A
Party that withdraws its membership in the Authority under either Section 7.1.1 or 7.1.2 shall be
responsible for paying its fair share of costs incurred by the Authority resulting from the Party’s
withdrawal, including costs from the resale of power contracts by the Authority to serve the
Party’s load and any similar costs directly attributable to the Party’s withdrawal, such costs being
limited to those contracts executed while the withdrawing Party was a member, and
administrative costs associated thereto. The Parties agree that such costs shall not constitute a
debt of the withdrawing Party, accruing interest, or having a maturity date. 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 costs
described above. Any amount of the Party’s funds held by the Authority for the benefit of the
Party that are not required to pay the Party’s costs described above shall be returned to the Party.
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. A
withdrawing party has the right to continue to participate in Board discussions and decisions
affecting customers of the CCA Program that reside or do business within the jurisdiction of the
Party until the withdrawal’s effective date.
7.3 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.
7.4 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
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Agreement
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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 in the manner agreed upon by the Party or Parties and the Authority. The Parties
agree that each Party may specifically enforce this section 8.1. In the event that nonbinding
mediation is not initiated or does not result in the settlement of a dispute within 120 days after
the demand for mediation 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
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.
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
4.12. Except that, any amendment to the voting provisions in Section 4.12 may only be made by
a three-quarters affirmative vote of the entire Board. 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.
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-19-
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
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. All notices required hereunder shall be delivered to:
The County of Alameda
Director, Community Development Agency
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Agreement
-20-
224 West Winton Ave.
Hayward, CA 94612
With a copy to:
Office of the County Counsel
1221 Oak Street, Suite 450
Oakland, CA 94612
if to [PARTY No. ____]
Office of the City Clerk
__________________________
__________________________
Office of the City Manager/Administrator
__________________________
__________________________
Office of the City Attorney
__________________________
__________________________
if to [PARTY No._____ ]
Office of the City Clerk
__________________________
__________________________
Office of the City Manager/Administrator
__________________________
__________________________
Office of the City Attorney
__________________________
__________________________
417
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Agreement
-21-
ARTICLE 9
SIGNATURE
IN WITNESS WHEREOF, the Parties hereto have executed this Joint Powers Agreement
establishing the East Bay Community Energy Authority.
By:
Name:
Title:
Date:
Party:
418
9/26/2016 Draft
Exhibit A
Page 1
EXHIBIT A
-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.)-
-
419
9/26/2016 Draft
Exhibit B
Page 1
DRAFT EXHIBIT B
-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 B is effective as of ________________.
Party kWh ([YEAR]*)
*Data provided by PG&E
420
DRAFT EXHIBIT C
- 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 C is effective as of ___________________.
Party kWh ([YEAR]*) Voting Share
Section 4.11.2
Total
*Data provided by PG&E
421
Community Choice Aggregation Feasibility Analysis DRAFT Contra Costa County
November, 2016 MRW & Associates, LLC
I- 1
Appendix I. MCE’s approval for inclusion of Contra
Costa
422
423
424
Attachment B
Project Management and JPA Formation
Project planning, program development and strategy support $150,000
JPA Agreement, CCE ordinance, General Counsel Services $100,000
Executive/staff salaries (initial 8 months)$400,000
Start up admininistrative costs (office rent, equipment, insurance, etc.)$150,000
TOTAL:$800,000
Technical and Energy Services
Technical Feasibility Study/Comparative Analysis $175,000
Implementation Plan Development $50,000
Update operating budget; revenue modeling for finance discussions $10,000
Power Supply RFP, vendor selection and contract negotiations $50,000
Rate Design/Rate Setting $50,000
Utility Service Fees $75,000
Assistance with NEM/FIT programs, registrations and compliance $50,000
CCE Bond $100,000
TOTAL:$560,000
Communications/Customer Enrollment*
Logo/Branding/Style Guide $25,000
Interactive website with 3 translations $45,000
Multilingual Collateral Design/Video $40,000
Printing $75,000
Earned and Paid Media $250,000
Community Outreach/Materials for Tabling $25,000
Customer Notifications (2 @ $1.00 each)$400,000
TOTAL:$860,000
Finance/Legal
Banking and Credit Services ‐ RFP, Selection, Negotiation and Paperwork $45,000
Power Supply Contract ‐ Legal Services $75,000
TOTAL:$120,000
Regulatory/Legislative
Participation in Regulatory Proceedings/Legal $50,000
Monitoring and Reporting $25,000
TOTAL:$75,000
Miscellaneous/Contingency $100,000
TOTAL:$2,515,000
*Assumes 2 notices to 200,000 customers in eligible cities and unincorporated County; includes
cost of design, print and postage
(1) Notes & Assumptions:
1. All costs associated with program implementation are fully recoverable through
early program revenues
2. This budget provides an estimate of project hard costs and does not include
internal staff time
3. Approximately $1.0 M of this budget could be covered by a thrid party line of
credit put into place ~ 6 months prior to launch; pre‐revenue credit will require a
guaranty
4. This budget does not include the credit requirements for the cost of power, utility
and supplier deposits, or Agency operational expenses
Contra Costa County Community Choice Program
DRAFT Implementation Budget (1)
425
426
427
INTERNAL OPERATIONS COMMITTEE-SPECIAL
MEETING 10.
Meeting Date:12/12/2016
Subject:Rooster and Barking Dog Ordinance
Submitted For: Beth Ward, Animal Services Director
Department:Animal Services
Referral No.: IOC 16/13
Referral Name: Rooster and Barking Dog Ordinance
Presenter: Beth Ward Contact: Beth Ward
(925)
Referral History:
On December 6, 2016, the Board of Supervisors referred to the Internal Operations Committee
development of an ordinance to authorize administrative penalties for barking dogs and other
noisy animals, and to limit the number of roosters on private property in the county
unincorporated areas. After receiving feedback from Contra Costa County residents, the Animal
Services Department found that the current Dog Barking Ordinance was insufficient and needed
to be strengthened. The Animal Services Department also found that the County lacks a Rooster
Ordinance governing the number of roosters a resident could own. After researching ordinances
around the Bay Area and the State, the Animal Services Director found that Orange and Solano
Counties' noise ordinances had the best practices to serve their community needs around noisy
animals.
Referral Update:
Today will be the first discussion of the proposed ordinance update. Attached is a clean copy of
the proposed ordinance update and also a version with tracked changes.
Recommendation(s)/Next Step(s):
CONSIDER recommendations of the Animal Services Director to update the current Dog Barking
Ordinance to authorize administrative penalties for animal noise violations and to prohibit the
harboring of more than four roosters on private property, and DETERMINE action to be taken.
Fiscal Impact (if any):
The fiscal impact is yet to be determined.
Attachments
Proposed Rooster and Barking Dog Ordinance Update_TRACKED CHANGES
428
Proposed Rooster and Barking Dog Ordinance Update_CLEAN VERSION
429
430
431
432
433
434
435
436
437
438
439
440
441
442
443
444
445
INTERNAL OPERATIONS
COMMITTEE-SPECIAL MEETING 11.
Meeting Date:12/12/2016
Subject:2016 YEAR-END REPORT ON COMMITTEE REFERRALS AND
THEIR DISPOSITION
Submitted For: David Twa, County Administrator
Department:County Administrator
Referral No.: N/A
Referral Name: N/A
Presenter: Julie DiMaggio Enea, IOC Staff Contact: Julie DiMaggio Enea
925.335.1077
Referral History:
At the end of each calendar year, the Internal Operations Committee reports to the Board its
activities and progress made on referrals from the Board. The report generally summarizes each
referral, describes the Committee's work on the referral during the calendar year, and includes a
recommendation as to the future disposition of the referral. The year-end report provides a basis
for a work plan for the ensuing year and helps to ensure continuity for multi-year referrals.
Referral Update:
Attached is a draft Order to the Board summarizing the activities and accomplishments of the
Internal Operations Committee in 2016 and recommending matters for referral to the 2017
Committee.
Recommendation(s)/Next Step(s):
REVIEW the Committee's work for 2016 and identify issues to be referred to the 2017 Internal
Operations Committee
Fiscal Impact (if any):
None.
Attachments
DRAFT 2016 IOC Year-End Productivity Report
446
INTERNAL OPERATIONS COMMITTEE
2016 PRODUCTIVITY REPORT
During 2016, the Internal Operations Committee (IOC) received 13 referrals from the Board of
Supervisors, made 16 reports to the Board, interviewed 17 candidates and made
recommendations to fill 30 seats for certain advisory bodies whose composition requirements
must be monitored. Our Committee appreciates the time and effort taken by the staff to the
Board’s advisory bodies to recruit, screen, and nominate individuals to our Committee for
approval and appointment by the Board. Their efforts in this regard allowed the IOC to focus
more of its time on the following subjects:
1. Small Business Enterprise (SBE) and Outreach Programs. The IOC accepted an SBE
Program report on October 24, 2016 from the County Administrator’s Office, covering the
period January 2015-June 2016, and reported out to the Board of Supervisors on November 8,
2016. This is a standing referral . REFER
2. County Financial Audit Program. Since 2000, the IOC reviews, each February, the annual
schedule of audits and best practices studies proposed by the Auditor-Controller. The Auditor-
Controller’s Office presented a report of their 2015 audits and the proposed 2016 Audit Schedule
to the IOC on February 29, 2016. This is a standing referral. REFER
3. Annual Report on Fleet Internal Service Fund and Disposition of Low Mileage Vehicles.
Each year, the Public Works Department Fleet Manager has analyzed the fleet and annual
vehicle usage, and made recommendations to the IOC on the budget year vehicle replacements
and on the intra-County transfer of underutilized vehicles, in accordance with County policy. In
FY 2008/09, following the establishment of an Internal Services Fund (ISF) for the County Fleet,
to be administered by Public Works, the Board requested the IOC to review annually the Public
Works department report on the fleet and on low-mileage vehicles.
The IOC received the 2015 annual fleet report on March 28, 2016 and reported out to the Board
of Supervisors on April 12, 2016. This is a standing referral. REFER
4. Local Bid Preference Program. In 2005, the Board of Supervisors adopted the local bid
preference ordinance to support small local businesses and stimulate the local economy, at no
additional cost to the County. Under the program, if the low bid in a commodities purchase is not
from a local vendor, any responsive local vendor who submitted a bid over $25,000 that was
within 5% percent of the lowest bid has the option to submit a new bid. The local vendor will be
awarded if the new bid is in an amount less than or equal to the lowest responsive bid, allowing
the County to favor the local vendor but not at the expense of obtaining the lowest offered price.
Since adoption of the ordinance, the IOC has continued to monitor the effects of the program
through annual reports prepared and presented by the Purchasing Agent or designee.
The Purchasing Services Manager made a report to the IOC on September 26, 2016 and the IOC
report out to the Board of Supervisors on November 15, 2016. This is a standing referral.
REFER
447
5. Advisory Body Recruitments. On December 12, 2000, the Board of Supervisors approved a
policy on the process for recruiting applicants for selected advisory bodies of the Board. This
policy requires an open recruitment for all vacancies to At Large seats appointed by the Board.
The IOC made a determination that it would conduct interviews for At Large seats on the
following bodies: Retirement Board, Fire Advisory Commission, Integrated Pest Management
Advisory Committee, Planning Commission, Treasury Oversight Board, Airport Land Use
Commission, Aviation Advisory Committee and the Fish & Wildlife Committee; and that
screening and nomination to fill At Large seats on all other eligible bodies would be delegated to
each body or a subcommittee thereof.
In 2016, the IOC submitted recommendations to the Board of Supervisors to fill 30 vacant seats
on various committees and commissions. The IOC interviewed 17 individuals for seats on the
Airport Land Use Commission, Aviation Advisory Committee, Integrated Pest Management
Advisory Committee, East Bay Regional Parks Advisory Committee, Fish & Wildlife
Committee, Resource Conservation District, and the Treasury Oversight Committee. In 2017,
the IOC will need to recruit and interview for multiple seats on the Retirement Board. This is a
standing referral. REFER
6. Process for Allocation of Propagation Funds by the Fish and Wildlife Committee. On
November 22, 2010, the IOC received a status report from Department of Conservation and
Development (DCD) regarding the allocation of propagation funds by the Fish and Wildlife
Committee (FWC). The IOC accepted the report along with a recommendation that IOC conduct
a preliminary review of annual FWC grant recommendations prior to Board of Supervisors
review. On April 25, 2016 the IOC received a report from DCD proposing, on behalf of the
FWC, 2016 Fish and Wildlife Propagation Fund Grant awards. The IOC approved the proposal
and, on May 10, recommended grant awards for six projects totaling $22,450, which the Board
of Supervisors unanimously approved. This is a standing referral. REFER
7. Advisory Body Triennial Review. Beginning in 2010 and concluding in 2011/2012, the
Board of Supervisors conducted an extensive review of advisory body policies and composition,
and passed Resolution Nos. 2011/497 and 2011/498, which revised and restated the Board’s
governing principles for the bodies. The Resolutions dealt with all bodies, whether created by the
BOS as discretionary or those that the BOS is mandated to create by state or federal rules, laws
or regulations. The Resolutions directed the CAO/COB’s Office to institute a method to conduct
a rotating triennial review of each body and to report on the results of that review and any
resulting staff recommendations to the Board, through the IOC, on a regular basis.
The first phase report of the current Triennial Review Cycle was considered by the IOC on April
13, 2015. At that time, the Supervisors approved many of the recommendations in the report.
However, they also asked the CAO’s Office to return with additional information about a
number of the advisory bodies. On October 12, 2015 the IOC accepted the follow-up report
from the County Administrator on outstanding issues and information requests stemming from
Phase 1 of the Board Advisory Body Triennial Review. The IOC reported back to the Board on
December 8 with results of Phase I of the review and recommendations for follow-up.
448
The IOC made four follow-up reports to the Board of Supervisors with additional
recommendations, concluding Phase I of the Triennial Review: Reconstitute the Agriculture
Task Force, April 2016; Reauthorize and update the Library Commission, April 2016; Modify
the bylaws of the Advisory Council on Aging, September 2016; and Abolish the Public and
Environmental Health Advisory Board.
The IOC will begin reviewing the Phase II Triennial Review recommendations in 2017. REFER
8. Waste Hauler Ordinance. On May 8, 2012, the Board of Supervisors referred to the Internal
Operations Committee a proposal to develop a waste hauler ordinance. The IOC received a
preliminary report from the Environmental Health (EH) Division of the Health Services
Department on May 14, 2012 and status report on November 13, 2013 showing substantial work
and progress. The IOC requested EH staff to bring a final draft ordinance to the Committee for
further consideration but staff subsequently identified issues with the interplay between the
proposal and current franchise agreements that had to be examined before the County could
proceed with an ordinance. The IOC has continued to work on a draft ordinance with staff and
the franchises throughout 2015 and 2016, and expects to bring a report to the Board of
Supervisors in early 2017. As this continues to be a work in progress, we recommend that this
referral be continued to the 2017 IOC. REFER
9. Social Media Policy. On June 17, 2014, the Board of Supervisors approved a social media
policy governing the use of various online engagement tools by County employees for business
communication purposes. The County Administrator requested the Office of Communications
and Media, with assistance from Risk Management and County Counsel, to develop guidelines
for use and training. Input and direction from the Internal Operations Committee in 2013 and
2014 shaped the contents of the umbrella policy. Due to staffing and resource limitations, the
implementation of the policy was deferred to 2016. On March 28, the IOC accepted a status
report from the OCM Director on implementation of the social media policy, including staff
training plans. TERMINATE
10. Animal Benefit Fund Review. On April 21, 2015, the Board of Supervisors received
several comments regarding the Animal Benefit Fund from members of the public during fiscal
year 2015/16 budget hearings. As part of budget deliberations, the Board directed staff to
include a review of the Animal Benefit Fund to a Board Standing Committee for further review.
On May 12, 2015, the Board of Supervisors adopted the fiscal year 2015/16 budget, including
formal referral of this issue to the Internal Operations Committee. On September 14, 2015 IOC
received a staff report summarizing prior year expenditures and current fund balance of the
Animal Benefit Fund. On March 28, 2016, the IOC approved a proposal to expand the animal
services donation program and reported out to the Board of Supervisors on April 19, 2016. The
Board Order directed the Animal Services Director to report annually to the IOC on the impact
of the Animal Benefit Fund on the community and families, creating a new standing referral.
REFER
11. Community Choice Energy. On August 18, 2015, the Board of Supervisors referred to the
IOC the topic of Community Choice (Energy) Aggregation. Community Choice Aggregation
449
(CCA) is the practice of aggregating consumer electricity demand within a jurisdiction or region
for purposes of procuring energy.
On March 15, 2016, the Board of Supervisors directed staff to work with interested cities in
Contra Costa County to obtain electrical load data from PG&E and conduct a technical study of
CCE alternatives. Fourteen Contra Costa cities participated in the study with nine contributing
towards the cost of the study. An outside consulted was engage to conduct the study, which was
presented to the IOC on December 12, 2016 and will be presented to the Board of Supervisors on
January 17, 2017. Pending further direction from the Board on this matter, it is recommended
that CCE remain on referral to the IOC. REFER
12. Property Assessed Clean Energy (PACE). On June 16, 2015, the Board of Supervisors
approved the recommendation of the IOC to direct the Department of Conservation and
Development (DCD) to establish an application process and accept applications from PACE
providers to operate within the unincorporated area of the county. The Board also approved the
form of an Operating Agreement the County would require PACE providers to enter into with
the County as a condition of operations. The purpose of the Operating Agreement is to protect
the County and the general public from the potential costs and risk of PACE programs. The
Operating Agreement requires PACE providers to participate in the State PACE Loss Reserve
Program, disclose financial costs and risks to participating property owners, and indemnify the
County from legal claims arising from the operation of PACE programs.
On November 17, 2015, the Board of Supervisors approved an Operating Agreement with the
Western Riverside Council of Governments (WRCOG) and adopted a resolution authorizing
WRCOG to operate the California HERO PACE financing program within the unincorporated
area of the county.
On November 1, 2016, the Board of Supervisors approved an Operating Agreement with the
California Statewide Communities Development Authority (CSCDA) to operate the
CaliforniaFirst PACE financing program in the unincorporated area of Contra Costa County.
TERMINATE
13. Animal Noise Ordinance Update. On December 6, 2016, the Board of Supervisors referred
to the IOC development of an ordinance to authorize administrative penalties for barking dogs
and other noisy animals, and to limit the number of roosters on private property in the county
unincorporated areas. The IOC received a report and recommendations from the Animal
Services Director on December 12, 2016. RECOMMENDED DISPOSITION TO BE
DETERMINED.
450
EXHIBIT A
LIST OF REFERRALS TO BE REMOVED
9. Social Media Policy
12. Property Assessed Clean Energy (PACE)
EXHIBIT B
LIST OF ITEMS TO BE REFERRED TO THE
2017 INTERNAL OPERATIONS COMMITTEE
Standing Referrals
1. Continued policy oversight and quarterly monitoring of the Small Business Enterprise
and Outreach programs, and e-Outreach
2. Review of the annual financial audit schedule
3. Review of annual Master Vehicle Replacement List and disposition of low-mileage
vehicles
4. Local Bid Preference Program
5. Advisory Body Candidate Screening/Interview
6. Fish and Wildlife Propagation Fund Allocation
7. Advisory Body Triennial Review
10. Animal Benefit Fund Review
Non-Standing Referrals
8. Waste Hauler Ordinance
11. Community Choice Energy Aggregation
13. Animal Noise Ordinance Update
451
2016 Committee:
Appointments: Date Appt Interviewed
IPM Advisory Cte 3/8/2016 3 7
HazMat Comm 3/8/2016 5 0
Treasury Oversight Comm 5/10/2016 2 1
Retirement Board 5/10/2016 1 0
Planning Comm 5/10/2016 1 0
Advisory Fire Comm 5/10/2016 1 0
Airport Land Use
Comm
6/7/2016 1 1
Affordable Housing Fin Comm 6/7/2016 3 0
EBRPD Park Advisory Comm 9/13/2016 1 1
Fish & Wildlife Comm 9/13/2016 1 3
HazMat Comm 10/18/2016 1 2
Resource Conservation District 10/24/2016 2 0
Law Library 12/20/2016 1 0
Mosquito & Vector Control 12/20/2016 2 0
Fish & Wildlife Comm 12/20/2016 2 6?
Aviation Advisory Committee 12/20/2016 2 4?
Resource Conservation District 12/20/2016 1 2
30 17
Reports to BOS:
Internal Audit Schedule NA
Community Choice Energy Tech
Study
3/15/2016
2015 Annual Report Internal Service
Fund for Fleet
4/12/2016
Reconstitute Ag Task Force 4/19/2016
Animal Benefit Fund 4/19/2016
Reauthorize the Library Comm 4/26/2016
Fish & Wildlife Propagation Funds 5/10/2016
PACE Operating Agreement HERO 6/21/2016
Add'l Fish & Wildlife Propagation
Fund
9/13/2016
Adv Council on Aging Bylaws 9/20/2016
PACE Operating Agreement - CA
First
11/1/2016
Abolish PEHAB 11/15/2016
Local Bid Preference Program 11/15/2016
SBE/Outreach Annual Report 11/8/2016
Community Choice Energy Tech
Study
1/17/2017
Animal Noise Ordinance 12/20/2016
Year-End Report 1/10/2017
452