HomeMy WebLinkAbout3.1 - 1188 Update on Alameda County Community Choice E
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STAFF REPORT
CITY COUNCIL
DATE: November 1, 2016
TO: Honorable Mayor and City Councilmembers
FROM:
Christopher L. Foss, City Manager
SUBJECT:
Update on Alameda County Community Choice Energy Program
Prepared by: Shannan Young, Environmental Coordinator
EXECUTIVE SUMMARY:
STAFF RECOMMENDATION:
FINANCIAL IMPACT:
As this is an informational item, there is no impact.
DESCRIPTION:
Authorized by California law in 2002, Community Choice Aggregation (CCA), also
known as Community Choice Energy (CCE), enables cities and county governments to
pool the electricity demand within their jurisdictions in order to procure or generate
electrical power supplies on behalf of the residents and businesses in their
communities. CCAs works partnership with the region’s existing utility (in the case of
Alameda County, Pacific Gas & Electric Company or “PG&E”). Under the partnership,
the CCA procures and/or generates electricity on behalf of its customers, while PG&E
continues to deliver power to homes and businesses, handles customer billing, and
maintains the grid.
A CCA’s responsibilities are limited to 1) the acquisition of electricity and 2) the setting
of associated rates. The local investor owned utility (“IOU”)—PG&E—remains
responsible for the transmission and distribution of the electrical power, along with the
collection of payments from the ratepayers. The CCA may provide its customer base
with electricity either by purchasing it from third persons or by generating its own power.
The cost of residual IOU services—transmission and distribution—is charged in addition
to the CCA rates when it bills ratepayers. (Pub. Util. Code, §366.2, subds. (d), (e), (f);
PG&E Electric Rule 22). CCA customers would not notice any change in their electric
service other than a CCA line item on their utility bill replacing PG&E electric generation
charges with the CCA’s electric generation charges.
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Benefits to participating in a CCA program include: 1) the ability to achieve Climate
Action Plan goals through significant reductions in greenhouse gas emissions, 2)
offering customers an energy choice and competitive electrical rates, and 3) local
economic development benefits including jobs creation associated with the
development of local power and new energy programs in the region.
In June 2014, the Alameda County Board of Supervisors voted unanimously to allocate
$1.3 million to explore the creation of a CCA program, and directed County staff to
undertake the steps necessary to evaluate its feasibility. County staff assembled a 39-
member CCA Steering Committee, which includes stakeholders from environmental and
social justice organizations, labor and local government; completed a Technical
Feasibility Study to examine hypothetical Alameda County CCA scenarios t hrough
2030; and formulated a Joint Powers Agreement (JPA) for the East Bay Community
Energy Authority (Authority). On October 4, 2016, the Alameda County Board of
Supervisors approved the JPA, which will, upon approval of at least three initial
participating jurisdictions, establish the Authority. The JPA document is included in
Attachment 1.
The proposed Authority would be governed by a Board of Directors, comprising one
elected representative from each city and county participating in the program. Fi nal
decisions regarding the specific level of renewable energy to be procured, prioritization
of local renewable energy and job development, and other governance issues will be
determined by the Board of Directors, as specified in the JPA. Once the CCA Pr ogram
is implemented, the Authority will enter into agreements with electric power suppliers
and other service providers and, based upon those agreements, work to provide
electrical power to residents and businesses at competitive rates.
Upon the California Public Utilities Commission approving the implementation plan
prepared by the Authority, the Authority can provide service to customers within its
member jurisdictions. If a public agency chooses to implement a CCA, all electric
customers within its geographic jurisdiction automatically become CCA customers,
unless a particular ratepayer chooses to “opt out” of CCA service. Residents who opt
out will continue to receive power from PG&E. Those who do not opt out will have their
power supplied by the CCA.
The Authority will have the power to enter into long term power purchase agreements,
acquire property, build energy-generating facilities, and issue revenue bonds. The Joint
Powers Agreement provides for a mechanism whereby all Authority Board votes a re
initially one-jurisdiction-one-vote, but any three representatives may request a “voting
shares vote” in which case a second vote is taken weighted based on energy usage.
Both must pass for a particular motion to pass. (JPA, § 4.12.2.) During the first two
years, the voting shares are based on total load within the jurisdiction, and they are
adjusted to reflect CCA customer annual usage thereafter.
There are currently five operational CCAs in California including Marin Clean Energy,
Sonoma Clean Power, CleanPowerSF (San Francisco), Lancaster Choice Energy and
Peninsula Clean Energy, with several more throughout the state that are currently under
development. The East Bay Clean Power Authority would potentially be the largest
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CCA created in California to date.
Technical Feasibility Study
On April 19, 2016, City Council received an update on the status of the CCA, including a
presentation on the draft findings of the Technical Feasibility Study (Technical Study).
The Technical Study was completed by Oakland consulting firm MRW & Associates in
June of 2016 and shows that implementing a CCA program has the potential to provide
the following benefits to the residents of Alameda County:
1. Provide customers a choice of power providers;
2. Increase local control over energy rates and other energy-related matters;
3. Provide electric rates that are competitive with those provided by the
incumbent utility;
4. Reduce greenhouse gas emissions arising from electricity use;
5. Increase local and regional renewable generation capacity;
6. Increase energy conservation and efficiency projects and programs;
7. Increase regional energy self-sufficiency; and
8. Encourage local economic and employment benefits through energy
conservation and efficiency projects.
Financing
Analysis to date of financing the East Bay Community Energy Authority has been
provided exclusively by Alameda County. Phase I costs, including hard costs and
compensated County staff time is approximately $1.33 million. The second and third
phases to establish and launch the CCA program are estimated at an additional $2.41
million, which includes the hard costs associated with JPA formation and program
development.
The JPA explicitly provides that the County will be reimbursed for all its actual i ncurred
expenses in creating both the Authority and the CCA program. Various sources for
funding additional startup-related expenses and services that may be necessary to
complete Phases II and III, up to $2.41 million, have been the subject of preliminar y
discussions with the County Administrator and Auditor-Controller. All start-up costs
associated with this project are fully reimbursable from revenue generated by
ratepayers during the first three years. At the October 4, 2016 Board of Supervisors
meeting, the County approved the steps necessary to secure the needed funding to
complete Phase II and Phase III.
The Authority is expected to seat its Board of Directors in early 2017, and initiate early
stages of operation at that time. The Authority will need to establish working capital to
cover its expenses leading up to the delivery of electricity, which is projected for fall of
2017. At this time, the source of the Agency’s working capital is not yet determined and
will be decided by the JPA Board upon its formation. Typically for CCA programs, this
capital is most often provided by a bank line of credit that requires a credit guarantee
until such time that the Authority’s customers have been enrolled and the program is
fully resourced. The Technical Study's pro forma analysis identified up to $51 million in
working capital needs, the majority of which would cover initial power purchases and be
repaid within five years of customer enrollment and ratepayer revenues. The financial
model showed that this level of financing could be paid back within that timeframe, while
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still building up a substantial reserve for the Authority in its early years. It is possible
that the Authority may seek some form of guaranty assistance from one or more of the
public agencies in the Authority although that is unknown at this time and is not part of
the JPA.
There is no request by Alameda County for financing support of the CCA program from
the City of Dublin.
Timeline
The County and cities that elect to participate in the East Bay Community Energy
Authority must do so by approving the execution of the Joint Powers Agreement and
adopting an ordinance electing to implement a CCA program. Cities electing to join the
CCA must do so by adopting the ordinance by December 31, 2016. The County is
expected to conduct its second reading and take final steps to formalize the JPA
following consideration by the cities, in either December 2016 or January 2017. If the
Authority is formed, the plan is to provide electricity to the first phase of customers by
fall 2017.
NOTICING REQUIREMENTS/PUBLIC OUTREACH:
None.
ATTACHMENTS:
1. East Bay Community Energy Authority Joint Powers Agreement
2. Technical Study for Community Choice Aggregation Program in Alameda County
October 4, 2016 County Approval Agreement
East Bay Community Energy Authority
- Joint Powers Agreement –
Effective _____________
Among The Following Parties:
Attachment 1
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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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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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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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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
__________________________
__________________________
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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:
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.)-
-
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
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
Technical Study for Community Choice Aggregation
Program in Alameda County
Prepared by:
With
MRW & Associates, LLC
1814 Franklin Street, Ste 720
Oakland, CA 94612
Tierra Resource
Consultants
Walnut Creek, CA
Economic Development
Research Group
Boston, MA
FINAL July 1 2016
Attachment 2
Community Choice Aggregation Feasibility Analysis Alameda County
July 2016 . MRW & Associates, LLC
Table of Contents
Executive Summary ................................................................................................................ i
Loads and Forecast ........................................................................................................................ i
CCA Power Supplies ...................................................................................................................... iii
Local Renewable Development ........................................................................................................... iii
Rate Results .................................................................................................................................. iv
Scenario 1 (Simple Renewable Compliance) ....................................................................................... iv
Scenario 2 (Accelerated RPS) ............................................................................................................... v
Scenario 3 (80% RPS by 2021) .............................................................................................................. v
Greenhouse Gas Emissions ........................................................................................................... vii
Sensitivity Analysis........................................................................................................................ ix
Macroeconomic and Job Impacts .................................................................................................... x
Energy Efficiency .......................................................................................................................... xii
Conclusions ................................................................................................................................ xiii
Chapter 1: Introduction ......................................................................................................... 1
What is a CCA? ...............................................................................................................................1
Assessing CCA Feasibility ................................................................................................................1
Chapter 2: Economic Study Methodology and Key Inputs ....................................................... 3
Alameda County Loads and CCA Load Forecasts ..............................................................................1
Energy Efficiency ............................................................................................................................4
CCA Supplies ..................................................................................................................................6
Power Supply Cost Assumptions .......................................................................................................... 9
Locally-Sited and Developed Renewables .......................................................................................... 11
Greenhouse Gas Costs ....................................................................................................................... 11
Other CCA Supply Costs...................................................................................................................... 12
PG&E Rate and Exit Fee Forecasts ................................................................................................. 12
PG&E Bundled Generation Rates ....................................................................................................... 12
PG&E Exit Fee Forecast ...................................................................................................................... 13
Pro Forma Elements and CCA Costs of Service ............................................................................... 14
Pro Forma Elements ........................................................................................................................... 14
Startup Costs ...................................................................................................................................... 16
Energy Efficiency Program Costs ........................................................................................................ 16
Administrative and General Cost Inputs ............................................................................................ 17
Cost of Service Analysis and Reserve Fund ........................................................................................ 17
Chapter 3: Cost and Benefit Analysis .................................................................................... 18
Scenario 1 (Renewable Compliance) ............................................................................................. 18
Rate Differentials ................................................................................................................................ 18
Residential Bill Impacts ...................................................................................................................... 19
Greenhouse Gas Emissions ................................................................................................................ 19
Scenario 2 (Accelerated RPS) ........................................................................................................ 20
Rate Differentials ................................................................................................................................ 20
Residential Bill Impacts ...................................................................................................................... 21
GHG Emissions ................................................................................................................................... 22
Scenario 3 (80% RPS by 2021) ....................................................................................................... 23
Community Choice Aggregation Feasibility Analysis Alameda County
July 2016 . MRW & Associates, LLC
Rate Differentials ................................................................................................................................ 23
Residential Bill Impacts ...................................................................................................................... 24
GHG Emissions ................................................................................................................................... 25
Chapter 4: Sensitivity of Results to Key Inputs ...................................................................... 26
Diablo Canyon Relicensing Sensitivity ........................................................................................... 26
Higher Renewable Power Prices Sensitivity ................................................................................... 27
Higher Exit Fee (PCIA) Sensitivity .................................................................................................. 28
Higher Natural Gas Prices Sensitivity ............................................................................................ 28
Lower PG&E Portfolio Cost Sensitivity .......................................................................................... 29
Stress Case and Sensitivity Comparisons ....................................................................................... 29
Conclusions ................................................................................................................................. 32
Chapter 5: Macroeconomic Impacts ..................................................................................... 33
How a CCA interacts with the Surrounding Economy ..................................................................... 33
How Job Impacts Are Measured ................................................................................................... 35
Scenario Results ........................................................................................................................... 35
Job and Gross Regional Product Total Impacts .................................................................................. 36
County Job impact by Stage of Job generation, Scenario 1 ............................................................... 38
County Job Impacts by Sector 2023 (Scenario 1) .............................................................................. 39
Focus on Construction Sector Jobs .................................................................................................... 40
Occupation Impacts for Alameda County, 2023 ................................................................................ 43
Chapter 6: Other Risks ......................................................................................................... 44
Financial Risks to CCA Members ................................................................................................... 44
Procurement-Related Risks .......................................................................................................... 44
Legislative and Regulatory Risks ................................................................................................... 45
PCIA Uncertainty .......................................................................................................................... 45
Impact of High CCA Penetration on the PCIA ................................................................................. 46
Bonding Risk ................................................................................................................................ 47
Chapter 7: Other Issues Investigated .................................................................................... 48
Funding, Costs, and Impacts of the Energy Efficiency Program Scenario ......................................... 48
“Minimum” CCA Size? .................................................................................................................. 50
Individuals and Communities Self-Selecting 100% Renewables ...................................................... 52
Competition with a PG&E Community Solar Program .................................................................... 53
Additional Local Renewables ........................................................................................................ 53
Chapter 8: Conclusions ....................................................................................................... 55
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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
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
roCA Rest of California
SB 350 Senate Bill 350
TURN The Utility Reform Network
Community Choice Aggregation Feasibility Analysis Alameda County
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Community Choice Aggregation Feasibility Analysis Alameda County
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Executive Summary
California Assembly Bill 117, passed in 2002, established Community Choice Aggregation 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. In June
2014, the Alameda County Board of Supervisors voted unanimously to allocate funding to
explore the creation of a Community Choice Aggregation (CCA) Program called East Bay
Community Energy (EBCE) and directed County staff to undertake the steps necessary to
evaluate the feasibility of a CCA. This feasibility study is in response to this Board Action.
In order to assess whether a CCA is “feasible” in Alameda 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 an Alameda County CCA would have to serve
Estimates the costs to start-up and operate the CCA
Considers scenarios with differing assumptions concerning the amount of carbon-free
power being supplied to the CCA so as to assess the costs and greenhouse gas (GHG)
emissions reductions possible with the CCA
Includes analysis of in-county renewable generation
Compares the rates that could be offered by the CCA to PG&E’s rates
Quantitatively explores the rate competiveness to key input variables, such as the cost of
natural gas
Explores what activities a CCA might take with respect to administering customer-side
energy efficiency programs
Calculates the macroeconomic development and employment benefits of CCA formation.
Loads and Forecast
Figure ES-1 provides a snapshot of Alameda County electric load in 2014 by city and by rate
class. As the figure shows, total electricity load in 2014 from Alameda County was
approximately 8,000 GWh. The cities of Oakland, Fremont, and Hayward were together
responsible for half the county load, with Berkeley, San Leandro, and Pleasanton also
contributing substantially. Residential and commercial customers made up the majority of the
county load, with smaller contributions from the industrial and public sectors.
To forecast CCA loads through 2030, MRW used a 0.3% annual average growth rate, which is
consistent with the California Energy Commission’s most recent electricity demand forecast for
PG&E’s planning area. This growth rate incorporates load reductions from the CCA’s energy
efficiency programs of about 6 GWh per year from 2021 through 2030. Figure ES-2 shows this
forecast by class, with the energy efficiency savings that are included in the forecast indicated by
the top (yellow) segment.
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Figure ES-1. PG&E’s 2014 Bundled Load in Alameda County
by Jurisdiction and Rate Class
Figure ES-2: CCA Load Forecast by Class, 2017-2030
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July 2016 iii MRW & Associates, LLC
CCA Power Supplies
The CCA’s primary function is to procure power 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. By law, the CCA 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 to 50% by 2030. The CCA may choose to
procure 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 (e.g., purchase
hydroelectric power rather than power from a fossil fuel generator).
The three supply scenarios that we considered are:
1. Minimum RPS Compliance: The CCA meets the state-mandated 33% RPS requirement
in 2020 and the 50% RPS requirement in 2030
2. More Aggressive: The CCA’s supply portfolio is set at 50% RPS from the first year
onward, plus additional amounts of non-RPS compliant large hydro power to reduce
GHG emissions
3. Ultra-Low GHG: The CCA’s supply portfolio is set at 50% RPS in the first year and
increases to 80% RPS by the fifth year.
In each case, we assumed that the RPS portfolio was predominately supplied with solar and wind
resources, which are currently the lowest cost sources of renewable energy in California. We
assumed that solar and wind each contribute 45% of the renewable energy supply. 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.
Local Renewable Development
The CCA may choose to contract with or develop renewable projects within Alameda County so
as to promote economic development or reap other benefits. For the purpose of this study, we
assume that the local renewable power development resulting from the CCA would be largely
solar. In developing the hypothetical portfolios, we made conservative assumptions about how
much local solar development would occur as a result of the CCA. A renewable potential study
performed for the California Public Utilities Commission (CPUC) estimated roughly 300 MW of
large solar supply in Alameda County. (Large solar in this study means ground-mounted utility-
scale solar farms).1 This estimate is based on an assessment that five percent of the estimated
6,000 MW of technical potential could be developed, largely as a result of land use conflicts or
slope issues that would make solar development unfeasible in certain areas. We assume that
over the forecast period through 2030, about 1/3 of the estimated 300 MW large solar supply
potential in Alameda County is developed as a result of commitments by the CCA. Additional
in-county, small solar projects are assumed to be added at 5-10 MW per year.
1 At about 8-10 acres per megawatt, this corresponds to 2,400 to 3,000 acres (3.75-4.7 square miles).
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As a result of feedback from reviews of the preliminary results, an additional case in which we
assume that 50% of the renewables are met with local generation. This case is discussed in
Chapter 7 and explored in greater detail in the Addendum.
Additional studies are available and underway2 assessing in more detail the solar potential in the
County, which preliminarily confirm the assumptions used here are conservative (i.e., low).
Once formed and operational, the CCA should investigate in greater detail the practical solar
potential in the County.
Rate Results
Scenario 1 (Simple Renewable Compliance)
Figure ES-3 summarizes the results of Scenario 1. The figure shows the total average cost of the
Alameda County CCA to serve its customers (vertical bars) and the comparable PG&E
generation rate (line).3 Of the CCA cost elements, the greatest cost is for non-renewable
generation followed by the cost for the renewable generation, which increases over the years
according to the RPS standards. Another important CCA customer cost is the Power Charge
Indifference Adjustment (PCIA), which is the CPUC-mandated charge that PG&E must impose
on all CCA customers. This fee is expected to decrease in most years beginning in 2019 and
have less of an impact on the CCA customer rates over time.
Under Scenario 1, the differential between PG&E generation rates and average cost for the
Alameda County CCA to serve its customer (aka the CCA rates) is positive in each year (i.e.,
CCA rates are lower than PG&E rates). As a result, Alameda County CCA 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.
2 For example, “Bay Area Smart Energy 2020,” available at
http://bayarearegionalcollaborative.org/pdfs/BayAreaSmartEnergy2020fin.pdf
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.
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Table ES-1 shows the average annual savings for Residential customers under Scenario 1. The
average annual bill for the residential customer on the Alameda County CCA program could
average about 7% lower than the same bill on PG&E rates.
Table ES-1. Scenario 1 Savings for Residential CCA Customers
Residential
Monthly
Consumption
(kWh)
Bill with PG&E
($)
Bill with
Alameda
County CCA ($)
Savings ($) Savings (%)
2017 650 147 142 5 3%
2020 650 160 145 15 9%
2030 650 201 188 13 6%
Scenario 2 (Accelerated RPS)
Under Scenario 2, Alameda County CCA meets 50% of its load through renewable power
starting from 2017, while 50% of its non-renewable load is met through hydro-electricity (i.e.,
overall 50% qualifying renewable. 25% hydro, 25% fossil or market). In this scenario, the
differential between PG&E generation rates and Alameda County CCA customer rates is slightly
lower than that under Scenario 1, but continues to follow a similar pattern over the years with
respect to PG&E rates. As was the case under Scenario 1, because of this positive differential,
Alameda County CCA customers’ average generation rate (including contributions to the reserve
fund) can be lower than PG&E’s average customer generation rate in each year under this
scenario as well.
The annual bill for a residential customer on the Alameda County CCA program in Scenario 2
could about 6.5% lower than the same bill on PG&E rates (on average over the 2017-2030 study
period). This is less than, but close to, bill savings under Scenario 1.
Scenario 3 (80% RPS by 2021)
Under this scenario, the Alameda County CCA 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 2021. In addition, 50% of its non-renewable supply is met through large hydro-electric
sources.
The differential between PG&E generation rates and Alameda County CCA customer rates in
Scenario 3 is the lowest of the three scenarios, as this scenario has the most expensive supply
portfolio (Figure ES-4). However, the expected Alameda County CCA rates continue to be lower
than the forecast PG&E generation rates for all years from 2017 to 2030. Although this positive
differential still allows for the collection of reserve fund contributions through the CCA’s rates in
all the years under consideration, between 2026 to 2028 the differential is very small. Similarly,
the annual bill for a residential customer on the Alameda County CCA program will be on
average only about 3% lower than the same customers on PG&E rates.
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Figure ES-3. Scenario 1 Rate Savings, 2017-2030
Figure ES-4. Scenario 3 Rate Savings, 2017-2030
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Greenhouse Gas Emissions
As modeled, there are no greenhouse gas benefits for Scenario 1—in fact there are net
incremental emissions. This is because both the CCA and PG&E are meeting the same RPS
requirements, but over 40% of PG&E’s supply portfolio is made up of nuclear4 and large hydro
generation, both of which are considered emissions-free.
The Alameda County CCA’s GHG emissions under Scenario 2 are much lower than those under
Scenario 1. This is due to the higher renewable content in the CCA’s generation mix under
Scenario 2, but more importantly, the 50% hydro content in the non-renewable generation mix.
Figures ES-5 compares the GHG emissions from 2017-2030 for the Alameda County CCA under
Scenario 2 with what PG&E’s emissions would be for the same load if no CCA is formed.
PG&E’s GHG emissions are initially comparable to, the CCA’s emissions. The expected
retirement of Diablo Canyon in 2025 increases PG&E’s emissions by approximately 30% in
2025.5 Following this, PG&E’s emissions are expected to decrease from 2026 to 2030 as PG&E
procures renewables to meet its mandated RPS goals. However, they still remain higher than the
CCA’s expected GHG emissions.
The results of Scenarios 1 and 2 illustrate that if the CCA wants to reduce is net carbon
emissions, it must include hydroelectric (or other low- or carbon-free resources) in its portfolio.
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 our PG&E emissions are
the PG&E emissions shown here are lower that the “current” emission. 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, resulting in GHG savings for
Scenario 2 rather than parity.
Similar to Scenarios 1 and 2, under Scenario 3 the Alameda County CCA’s GHG emissions first
increase from 2017 to 2019 as the CCA is phased in into the entire county. However, in Scenario
3 this increase is partially offset by the increasing renewable content in the CCA’s supply mix
(Figure ES-6). Thus the CCA’s emissions in this scenario grow at a slower rate from 2017 to
2019 than in the first 2 scenarios, then decrease until 80% renewable supply is achieved in 2021,
and remain flat thereafter. The CCA’s GHG emissions under this scenario are lower than
PG&E’s expected emissions for the same load if no CCA is formed, for all years except for 2017
for which the emissions are comparable.
4 40% of PG&E portfolio is nuclear and hydro 2017 -2024; in 2024 the Diablo Canyon retires and is replaced by gas-
fired generation.
5 Between when this study was conducted and the final report released, PG&E announced its intention to retire
Diablo Canyon at the end of its current license and replace it with storage, energy efficiency and renewables.
Qualitatively, if Diablo Canyon is replaced with storage etc., PG&E GHG emissions would be significantly lower
than the PG&E base case (i.e., the big jump up on PG&E GHG emissions in 2025 would not occur).
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Figure ES-5. Scenario 2 GHG Emissions by Year (PG&E Normal Hydro Conditions)
Figure ES-6. Scenario 3 GHG Emissions by Year PG&E Normal Hydro Conditions
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Sensitivity Analysis
In addition to the base case forecast described above, MRW assessed alternative cases to
evaluate the sensitivity of the results to possible conditions that could impact the Alameda
County CCA’s rate competitiveness. The key factors are summarized in Table ES-2.
Table ES-2.
Factor Sensitivity Change
Relicensing Diablo Canyon6 Increases PG&E’s generation rates by ~30%7
Increased cost of renewable power 10% higher through 2021, 20% higher in 2021
and 2022, and 30% higher after 2022
High PCIA (“exit fee”) Retains the high PCIA expected in 2018
(2.1¢/kWh) through 2030
High Natural Gas Prices
US Energy Information Administration’s High Gas
Price Scenario, which is about 60% higher than
the base case price
Low PG&E Rates PG&E rates 10% lower than base forecast
Stress Scenario Combined impact of high renewable costs, high
PCIA, high gas price and low PG&E rates.
The sensitivity results are shown as the difference between the annual average PG&E generation
rate and the Alameda County CCA rate8 and are shown in Figure ES-7. Scenario 1 (RPS
Compliance) is the least costly scenario for the CCA and therefore has the highest rate
differentials under most of the sensitivity cases considered. Scenario 2 (Accelerated RPS),
though still quite competitive with PG&E, fares slightly worse, with a rate differential typically
about 8% lower than in Scenario 1. Scenario 3 (80% RPS by 2021) has the highest renewable
content and is the costliest scenario, with rate differentials much lower than those in the other
two scenarios. While Scenario 3 is anticipated to be competitive with PG&E in most cases (on
average), the margins are much lower, particularly in the “High Renewable Prices” sensitivity
6 Between when this study was conducted and the final report released, PG&E announced its intention to retire
Diablo Canyon at the end of its current license and replace it with storage, energy efficiency and renewables.
Qualitatively, if we replaced DC with storage, energy efficiency and renewables, the net result would be PG&E
costs that are between the base PG&E cost and the Diablo Canyon Relicense).
7 The new cooling system, which would be required per state regulations implementing the Federal Clean Water
Act, Section 316(b), would alone have an estimated cost of $4.5 billion. It is because of these very high costs that
the base case assumes the that power plant is retired.
8The Alameda County CCA rate includes the PG&E exit fees (PCIA charges) that will be charged to CCA
customers but does not include the rate adjustment for the reserve fund.
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case, and they become negative in the “Low PG&E rates” sensitivity case (i.e., CCA customer
rates are higher than PG&E rates).
In the stress case,9 Alameda County CCA customer rates exceed PG&E customer rates on
average over the 2017-2030 period for all three scenarios, with the rate differential being highest
in Scenario 3 at -1.5¢/kWh. This is double the Scenario 2 stress case rate differential of -
0.75¢/kWh.
Figure ES-7. Difference Between PG&E Customer Rates and CCA Customer Rates Under
Each Sensitivity Case and Supply Scenario, 2017-2030 Average (i.e., positive vertical axis
means PG&E rates higher than CCA rates).
Macroeconomic and Job Impacts
The local economic development and jobs impacts for the three 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 CCA activities (e.g., construction
jobs at a new solar power plant or energy efficiency device installers), but also how the rate
savings that County households and businesses might experience with a CCA ripple through the
local economy, creating more jobs and regional economic growth.
Table ES-3 and Figure ES-8 illustrate this through high-level results expressed as average annual
job changes for the three CCA scenarios. While Scenarios 1 and 2 create nearly identical direct
jobs (due to comparable investment in local renewable projects), Scenario 1 creates far more
9 Stress Scenario assumes the risk cases no favorable to the CCA: Hi gh Renewable Prices, High PCIA, High Natural
Gas Prices, and Low PG&E rates.
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TOTAL jobs. This is due to the higher bill savings under Scenario 1. Scenario 3 creates a few
more direct jobs, but far fewer total jobs, due to decreased bill savings as compared to the other
two scenarios. As a result, its total job impact is 55 percent of the Scenario 1 total job impact.
Figure ES-8. Alameda County Total Job Impacts by Scenario
Table ES-3. Average Annual Jobs created in Alameda County by the CCA –
Direct and Total Impacts
2017 – to – 2030 County Impacts
CCA
Scenario
Local Capture on RE
investments
(billion$)
Bill Savings
(billion$)
Average
Annual
DIRECT Jobs
Average
Annual
TOTAL Jobs
1 $0.42 $1.57 165 1,322
2 $0.42 $1.51 166 1,286
3 $0.45 $0.52 174 731
The economic activity generated by the CCA results in incremental employment in a variety of
sectors. Figure ES-9 shows the job impacts (direct and indirect) by category for Scenario 1 in the
year 2023 (the year of maximum impact). It may be surprising that the non-direct stage of
Community Choice Aggregation Feasibility Analysis Alameda County
July 2016 xii MRW & Associates, LLC
economic stimulation for the county creates a more pronounced set of occupational opportunities
due to the magnitude of net rate savings benefitting all customer segments within the county.
Figure ES-9. Occupational Impacts Scenario 1, 2023
Energy Efficiency
The three cases each assumed approximately 6 GWh of annual incremental energy efficiency
savings directly attributable to CCA efficiency program administration. This value is based on
forecasts from the California Energy Commission, and take into account the savings being
achieved/allocated to PG&E as well as the mandates from Senate Bill 350.
A CCA has a number of options with respect to administering energy efficiency programs. First,
it can rely upon PG&E to continue to all energy efficiency activities in its area, with some input
to insure that monies collected from CCA customers flow back to the area. This is the path that
two of the four active California CCAs have chosen (Sonoma Clean Power and Lancaster Choice
Energy). Second, the CCA can apply to the CPUC to use monies collected in PG&E rates for
energy efficiency programs and administration. These CCA efficiency programs can be for CCA
customers only or for all customers in the CCA region, no matter their power provider. If the
CCA chose the latter path, greater funds are available (including for natural gas efficiency
programs). MCE Clean Energy has chosen this latter path. Our modeling assumed the more
conservative former one (i.e., offer efficiency programs to only CCA-served residents and
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July 2016 xiii MRW & Associates, LLC
businesses). Third, the CCA supplement or supplant these funds though revenues collected by
the CCA.
Conclusions
Overall, a CCA in Alameda County appears favorable. Given current and expected market and
regulatory conditions, an Alameda County CCA should be able to offer its residents and business
electric rates that are a cent or more per kilowatt-hour (~8%) 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 CCA portfolio (Scenario 3), combined with
other negative factors, do PG&E’s rates become consistently more favorable than the CCAs.
An Alameda County CCA would also be well positioned to help facilitate greater amounts
renewable generation to be installed in the County. While the study assumed a relatively modest
amount for its analysis—about 175 MW, other studies suggest that greater amounts are possible.
Because the CCA 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 CCA in the County than
without it.
The CCA 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 CCA 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. For example, even assuming that the CCA
implements a portfolio with 50% qualifying renewables and meets the 50% of the remaining
power with carbon-free hydropower, it would only then just barely result in net carbon
reductions. However, the extent to which GHG emissions reductions could occur is also a
function of the amount of hydroelectric power that PG&E is able to use. If hydro output
(continues) to be below historic normal levels, then the CCA should be able to achieve GHG
savings, as long as it is also contracting for significant amounts of carbon-free (likely
hydroelectric) power. Therefore, if carbon reductions are a high priority for the CCA, a
concerted effort to contract with hydroelectric or other carbon-free generators would be needed.
A CCA can also offer positive economic development and employment benefits to the County.
At the peak, the CCA would create approximately 2300 new jobs in the region. The large amount
for be for construction trades, totaling 440 jobs. What may be surprising is that much for the
jobs and economic benefit come from reduced rates. Residents, and more importantly
businesses, can spend and reinvest their bill savings, and thus generate greater economic impacts.
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Chapter 1: Introduction
The Alameda County Board of Supervisors voted unanimously in June, 2014 to allocate funding
to explore the creation of a Community Choice Aggregation (CCA) Program and directed
County staff to undertake the steps necessary to evaluate the feasibility of a CCA. This Technical
Study is in response to that Board Action.
What is a CCA?
California Assembly Bill 117, passed in 2002, established Community Choice Aggregation 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 CCA 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 CCA as it does for its own full -
service customers. By state law, PG&E also must provide all metering and billing services, its
customers receiving a single electric bill each month from PG&E, which would differentiate the
charges for generation services provided by the CCA as well as charges for PG&E delivery services.
Money collected by PG&E on behalf of the CCA is remitted in a timely fashion (e.g., within 3
business days).
As a power provider, the CCA must abide by the rules and regulations placed on it by the state and
its regulating agencies, such as maintaining demonstrably reliable supplies and fully cooperating with
the State’s power grid operator. However, the State has no rate-setting authority over the CCA; the
CCA may set rates as it sees fit so as to best serve its constituent customers.
Per California law, when a CCA is formed all of the electric customers within its boundaries will be
placed, by default, onto CCA service. However, customers retain the right to return to PG&E service
at will, subject to whatever administrative fees the CCA may choose to impose.
California currently has four active CCA Programs: MCE Clean Energy, serving Marin County
and selected neighboring jurisdictions; Sonoma Clean Power, serving Sonoma County,
CleanPowerSF, serving San Francisco City and County, and Lancaster Choice Energy, serving
the City of Lancaster (Los Angeles County). Numerous other local governments are also
investigating CCA formation, including Los Angeles County, San Mateo County, Monterey Bay
region, Santa Barbara, San Luis Obispo and Ventura Counties; and Lake County to name but a
few.
Assessing CCA Feasibility
In order to assess whether a CCA is “feasible” in Alameda 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 an Alameda County CCA would have to serve.
Estimates the costs to start-up and operate the CCA.
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Considers three scenarios with differing assumptions concerning the amount of
carbon-free power being supplied to the CCA so as to assess the costs and
greenhouse gas emissions reductions possible with the CCA.
Includes analysis of in-county renewable generation.
Compares the rates that could be offered by the CCA to PG&E’s rates.
Quantitatively explores the rate competiveness of the three scenarios to key input
variables, such as the cost of natural gas.
Explores what activities a CCA might take with respect to administering
customer-side, energy efficiency programs
Calculates the macroeconomic development and employment benefits of CCA
formation.
This study was conducted by MRW & Associates, LLC. MRW was assisted by Tierra Resource
Consultants, who conducted all the research and analysis related to energy efficiency. MRW was
also assisted by Economic Development Research Group, which conducted all of 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
CCA 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
The section summarizes the key inputs and methodologies used to evaluate the cost-effectiveness
and cost-competitiveness of the CCA under different scenarios. It considers the requirements that
an Alameda County CCA would need to meet, the resources that the County has available or
could obtain to meet these requirements, and the PG&E rates that the CCA would be competing
against. It also describes the pro forma analysis methodology that is used to evaluate the
financial feasibility of the CCA.
Understanding the interrelationships of all the tasks and using consistent and coherent
assumptions throughout are critical to delivering a quality work product. 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 integrations 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 and outcome of the energy efficiency analysis.
Two important points are highlighted in this figure. First, it is critical that wholesale power
market and prices assumptions are consistent between the CCA and PG&E. While there are
reasons that one might have lower or higher costs than the other for a particular product (e.g.,
CCAs 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. To apply power cost assumptions to the CCA than to PG&E,
such as simply escalating PG&E rates while deriving the CCA rates using a bottom-up approach,
will result in erroneous results. Second, virtually all elements of the analysis feed into the
economic and jobs assessment. As is described in detail in Chapter 5, the Study here 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.
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Figure 1. Task Map
Economic & Jobs
Analysis
Load
Analysis
Customer &
Load Forecast
CCA Rates &
Bills
Pro Forma
Analysis
Supply Costs
& Options
Energy Efficiency
Analysis
PG&E Rates &
Bills
PG&E Load
Data
Wholesale
Assumptions
CCA
Assumptions
PG&E
Assumptions
CCA
Competitiveness
County &
Regional
Economic
Benefits
County Econ.
Assumptions
Community Choice Aggregation Feasibility Analysis Alameda County
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Alameda County Loads and CCA Load Forecasts
MRW used PG&E bills from 2014 for all PG&E bundled service customers within the Alameda
County region as the starting point for developing electrical load and peak demand forecasts for
the Alameda County CCA program.10 Figure 2 provides a snapshot of Alameda County load in
2014 by city and by rate class. PG&E’s total electricity load in 2014 from Alameda County
bundled customers was approximately 8,000 GWh.11 The cities of Oakland, Fremont, and
Hayward were together responsible for half the county load, with Berkeley, San Leandro, and
Pleasanton also contributing substantially. Residential and commercial customers made up the
majority 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, with the exception of the city of Berkeley. The city of Berkeley’s load has a
significant public-sector footprint due to the presence of the University of California, Berkeley.
Figure 2. PG&E’s 2014 Bundled Load in Alameda County by Jurisdiction and Rate Class
10 Detailed monthly usage data provided by PG&E to Alameda County.
11 As determined from bill data provided by PG&E. “Bundled” load includes only load for which PG&E supplies the
power; it excludes load from Direct Access customers and load met by customer self -generation.
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Figure 3. PG&E’s 2014 Bundled Load in Alameda County by Rate Class
To estimate CCA loads from PG&E’s 2014 bundled loads, MRW assumed a CCA participation
rate of 85% (i.e., 15% of customers opt to stay with PG&E) and a three-year phase in period
from 2017 to 2019, with 33% of potential CCA load included in the CCA in 2017, 67% in 2018,
and 100% in 2019. To forecast CCA loads through 2030, MRW used a 0.3% annual average
growth rate, consistent with the California Energy Commission’s most recent electricity demand
forecast for PG&E’s planning area.12 This growth rate incorporates load reductions from energy
efficiency of about 6 GWh per year from 2021 through 2030.
The CCA load forecast is summarized in Figure 4, which shows annual projected CCA loads by
class, with the energy efficiency savings that are included in the forecast indicated by the top
(yellow) segment.
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/
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Figure 4: CCA Load Forecast by Class, 2017-203013
To estimate the CCA’s peak demand in 2014, MRW multiplied the load forecast for each
customer class by the PG&E’s 2014 hourly ratio of peak demand to load for that customer
class.14 MRW extended the peak demand forecast to 2030 using the same growth rates used for
the load forecast. (Peak demand is the maximum amount of power the CCA would use at any
time during the year. It is measured in megawatts (MW). It is important because a CCA must
have enough power plants on (or contracted with) at all times to meet the peak demand.) This
forecast is summarized in Figure 5.
13 Load forecasted assumes 85% participation.
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 6. CCA Peak Demand Forecast, 2017-2030
Energy Efficiency
The assessment of energy efficiency potential in Alameda County completed for this feasibility
study used outputs from the 201315 and 201516 Energy Efficiency Potential and Goals studies
developed by the CPUC. These CPUC studies define the technical and economic potential for
energy efficiency in PG&E’s service territory. They also determine the market potential used to
set goals and budgets for PG&E’s energy efficiency programs.17 Because of its size, varied
economy, diverse demographics, and range of climates, it is likely that both energy use
characteristics and the potential for energy efficiency in Alameda County is consistent with the
potential for energy efficiency in PG&E’s overall service territory, with some exceptions, such
as a reduced presence of agricultural and oil extraction loads found elsewhere in the state. Based
on these consistencies, this analysis concludes that the energy efficiency potential for electricity
in PG&E’s overall service territory as presented in the CPUC studies can be allocated to
Alameda County in proportion to overall electricity sales, which average approximately 7.5% of
total annual PG&E electricity sales.
Using this approach to interpreting the output from CPUC potential studies, Table 1 provides a
range of estimates of technical and economic potential in Alameda County for a forecast horizon
from the 2017 to 2024. This provides a general indication of the total amount of energy
efficiency potential that exists in Alameda County that PG&E and any CCA administered
programs would be serving.
15 2013 California Energy Efficiency Potential and Goals Study, Final Report. Prepared for the Californ ia Public
Utilities Commission by Navigant Consulting, Inc. February 14, 2014
16 Energy Efficiency Potential and Goals Study for 2015 and Beyond, Stage 1 Final Report. Prepared for the
California Public Utilities Commission by Navigant Consulting, Inc. Reference No.: 174655, September 25, 2015
17 See Appendix A for a discussion of technical, economic, and market potential.
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Table 1. Alameda County Average Technical and Economic Energy Efficiency Potential
Metric Technical Potential Economic Potential
Range (% of sales) 21% 16% 18% 15%
Potential (GWh) 1,623 1,237 1,391 1,159
Table 2 provides a forecast of the market potential for energy efficiency based on a similar
analysis market forecasts from the CPUC potential studies. The row labeled “PG&E Goals”
represents Alameda County’s share of the market potential forecast which formed the basis for
PG&E’s 2015 energy efficiency program portfolio savings targets.18 That is, because Alameda
is in PG&E’s service area, it provides, and will continue to provide, energy efficiency programs
to Alameda county residents and businesses. This row shows this amount. The row labeled
“High Savings Scenario” represents the energy efficiency savings attributable to Alameda
County in the CPUC potential study’s high savings scenario.19 The row labelled “Incremental
Potential” is the difference between PG&E’s 2015 portfolio goals for Alameda County and the
high savings scenario for the County. This row represents the total market potential that could be
served by CCA administered programs. The forecast presented in Table 2
Table 2. Alameda County Incremental Energy Efficiency Market Potential (GWh)20
Year 2017 2018 2019 2020 2021 2022 2023 2024
Alameda Co. Component of
PG&E Goals 25.9 35.8 24.6 29.4 41.1 48.2 50.0 25.9
Alameda Co. of High Savings
Scenario 44.2 59.8 56.6 65.6 71.7 84.2 88.4 44.2
Incremental Potential 18.3 24.0 32.0 36.3 30.6 36.0 38.4 18.3
While there are countless opportunities and approaches to achieve energy efficiency, several
examples of technologies and programs that will yield savings above what is being targeted
through the current portfolio of PG&E programs operating in Alameda County are listed below.
This includes initiatives that might compliment and leverage existing technologies or programs,
or highlight emerging opportunities that are in design or early deployment.
High efficiency LED lighting initiatives targeting high lumen per watt technologies.
18 Net GWh, as defined by the CEC Mid Additional Achievable Energy Efficiency (AAEE) forecast
19 Referred to as the High AAEE Potential Scenario
20 Savings values do not include energy efficiency potential associated with building codes, appliance standards, or
estimates for the agricultural or mining market sectors.
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Advanced controls for lighting and platforms that integrate advanced building
information & energy management systems.
Increased use of over 50 market ready funding and financing products that can be used
to implement sustainability projects in all market sectors.
High Opportunity Programs and Projects (HOPPs) being submitted in response to
AB802, such as the Residential Pay-for-Performance HOPP being proposed by PG&E
may provide an opportunity to drive higher participation Property Assessed Clean
Energy (PACE) programs currently operating throughout Alameda County.
CCA Supplies
The CCA’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.21 In addition to simply meeting the energy and capacity needs of its
customers, the CCA must meet other procurement objectives. By law, the CCA 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 to 50% by
2030. The CCA may 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 CCA 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 Alameda County CCA would be taking over these procurement responsibilities from PG&E
for those customers who do not opt out of the CCA to remain bundled customers of PG&E. To
retain customers, the CCA’s offerings and rates must compete favorably with those of PG&E.
The CCA’s specific procurement objectives, and its strategy for meeting those objectives, will be
determined by the CCA through an implementation plan, startup activities and ongoing
management of the CCA. The purpose of this study is to assess the feasibility of establishing a
CCA to serve Alameda County based on a forecast of costs and benefits. This forecast requires
making certain assumptions about how the CCA will operate and the objectives it will pursue. To
address the uncertainty associated with these assumptions, we have evaluated three different
supply scenarios and have generally made conservative assumptions about the ways in which the
CCA would meet the objectives discussed above. In no way does this study prescribe actions to
be taken by the CCA should one be established.
The three supply scenarios that we considered are:
21 The California Public Utilities Commission (CPUC) requires that load serving entities like CCAs demonstrate that
they have procured resource adequacy capacity to meet at least 115% of their expected peak load. Since Alameda
falls within the Greater Bay Area Local Reliability Area, it must also meet its share of local resource adequacy
requirements.
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1. Minimum RPS Compliance: The CCA meets the state-mandated 33% RPS requirement
in 2020 and the 50% RPS requirement in 2030;
2. More Aggressive: The CCA’s supply portfolio is set at 50% RPS from the first year
onward, plus additional amounts of non-RPS compliant large hydro power to reduce
GHG emissions;
3. Ultra-Low GHG: The CCA’s supply portfolio is set at 50% RPS in the first year and
increases to 80% RPS by the fifth year.
To evaluate these scenarios, we assumed a simple portfolio consisting of RPS-eligible 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 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 contribute 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.
As mentioned above, the CCA may choose to source a portion of its supply from local resources.
Alameda County has significant potential for both wind and solar production. The wind resource
is located in the Altamont Pass and largely consists of repowering existing turbines with a
smaller number of much larger turbines. Costs are generally competitive with other California
wind areas, however, the ability to develop projects is constrained by environmental impacts,
primarily avian mortality in the Altamont Pass. A Programmatic Environmental Impact Report
(PEIR) for the Alameda County portion of the Altamont Pass repowering would allow
development of up to 450 MW. Since this amount of capacity may be developed regardless of
whether the CCA is formed, and CCA local procurement wouldn’t necessarily increase the
amount of wind developed in the Altamont Pass, we have made the conservative assumption that
the wind portfolio would effectively be from projects located outside of Alameda County. Thus,
for the purpose of this study, we assumed that all of the local procurement by the CCA would be
from solar energy, including a mix of smaller and larger projects.22
Figure 7 through Figure 9 show the assumed build-out of new resources under each of the three
scenarios outlined above.
22 Note that customer-owned generation, such as rooftop photovoltaic panels, is reflected in the load forecast rather
than considered part of the supply portfolio. (I.e., the load forecast is what the CCA must serve, not the gross
consumption at the home prior to factoring in customer -side PV.)
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Figure 7. Senario 1 CCA Build-Out
Figure 8. Scenario 2 CCA Build-Out
Figure 9. Scenario 3 CCA Build-Out
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Power Supply Cost Assumptions
As discussed above, the CCA 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 10, the products to be purchased by the CCA consist generally of
energy, capacity and renewable attributes (which for counting purposes take the form of
renewable energy credits, or RECs).23
Figure 10. Power Supply Cost Elements
The CCA will be procuring supplies from the same competitive market for resources as PG&E.
As a result, we assume that the costs for renewable and non-renewable energy and for resource
adequacy capacity are the same for the CCA as for new purchases made by PG&E (as used in
our forecast of PG&E rates discussed below). Wholesale market prices for electricity in
California are largely driven by the cost of operating natural gas fueled power plants, since these
plants typically have the highest operating costs and are the marginal units. As a result, 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 for use in determining costs for the CCA and PG&E. Capacity prices are based on prices
for resource adequacy contracts reported by the CPUC.
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 CCAs in 2015 and early
2016, finding an average price of $49/MWh for the solar contracts, $55/MWh for wind power
23 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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and $80/MWh for geothermal.24 We used these prices as the starting point for our forecast of
CCA renewable energy procurement costs. For geothermal, which is a relatively mature
technology, we assumed that new contract prices would simply escalate with inflation. 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. Thus we have held solar and wind prices constant in
nominal dollars through 2020. Beyond 2020, with increasing competitive pressure associated
with the drive to a 50% RPS and the anticipated phase-out of federal tax incentives (offset in part
by continued declining technology costs), we would expect prices to increase somewhat and
have assumed they escalate at the rate of inflation. In addition to this base case price outlook, we
also consider a high solar cost scenario based on work performed by Lawrence Berkeley
Laboratory 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 11 shows the resulting solar price forecasts for the two scenarios.
Figure 11. Solar Price Forecast
24 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
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).
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Locally-Sited and Developed Renewables
As discussed above, the CCA may choose to contract with or develop renewable projects in the
local area to promote economic development or other benefits. For the purpose of this study, we
assume that incremental local development resulting from the CCA would be largely solar. Since
the solar resource in Alameda County is not as strong as in the desert and inland areas where new
utility-scale projects are typically developed (and upon which the above solar price forecast was
developed), solar generation costs in Alameda County are expected to be somewhat higher than
our price forecast. Based on renewable energy supply curves developed for the CPUC, we
assume a 15% premium for projects located in Alameda County.25
Given the limited open space for very large solar projects in the County, we expect a portion of
the local projects included in a hypothetical CCA portfolio to be smaller in size (e.g., < 3 MW).
Smaller solar projects tend to have higher generation costs since they don’t have the same
economies of scale as the larger projects upon which our estimates of market prices are based.
We have assumed a 55% generation cost premium for smaller projects, based on the same supply
curve study referenced above. Future price changes and economies of scale might lower this
value.
In developing the hypothetical portfolios depicted in Figure 7 through Figure 9, we made
conservative assumptions about how much local solar development may occur as a result of the
CCA. The supply curve study performed for the CPUC estimated roughly 300 MW of solar
supply in Alameda County, based on an assessment that five percent of the estimated 6,000 MW
of technical potential could be developed, largely as a result of land use conflicts or slope issues
that would make solar development infeasible in certain areas. We assume that over the forecast
period through 2030, about 1/3 of the estimated 300 MW large solar supply potential in Alameda
County is developed as a result of commitments by the CCA.
A discussion of the impacts and implications of greater local renewables can be found in Chapter
7.
Greenhouse Gas Costs
MRW based its forecast of the prices for GHG allowances on the results of the California Air
Resources Board’s (ARB’s) auctions for Vintage 2015 allowances.26 The Vintage 2015
Allowances were increased annually in proportion to the auction floor price increases stipulated
by the ARB’s cap-and-trade regulation.27
Table 3 GHG Allowances price
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
$/tonne 14.0 15.0 16.0 17.2 18.4 19.6 21.0 22.4 24.0 25.6 27.4 29.3 31.3 33.5
25 CPUC RPS calculator (RETI 2.0)
26 Auction results available at http://www.arb.ca.gov/cc/capandtrade/auction/results_summary.pdf.
27 California Code of Regulations, Title 17, Article 5, Section 95911 .
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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, approximately $5 per megawatt delivered.
Other CCA Supply Costs
The CCA is expected to incur additional costs associated with its procurement function. For
example, if the CCA 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 CCA would also incur costs charged by the California Independent System Operator
(CAISO) for ancillary services (activities required to ensure reliability) and other expenses.
MRW added 5.5% to the CCA’s power supply cost to cover these CAISO costs. Finally, we
added an expense associated with managing the CCA’s renewable supply portfolio. Based on an
analysis of the expected CCA 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 CCAs 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
CCA will need to sell the excess, 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 CCA exit fees in order to
compare the projected rates that customers would pay as Alameda County CCA 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 30-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 Alameda County CCA’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 just slightly faster than
inflation through 2030, with 2030 rates 3% 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:
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1. An initial period of faster rate growth through 2023 (1.3% above inflation);
2. A period of rate decline from 2023-2026 (2.5% below inflation) primarily due to the
retirement of Diablo Canyon28; and
3. A period of dampened rate growth through 2030 (0.2% 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 12, on
both a nominal and constant-dollar basis.
Figure 12: 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 CCA 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 CCA. The
total cost of these resources is compared to a market-based price benchmark to calculate the
“stranded costs” associated with these resources, and CCA 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 2030, using assumptions consistent with those
used in the PG&E rate model. Based on our modelling, we expect the PCIA to increase by 8%
over the 2016-2018 period (4% in constant dollars) and subsequently to decline in most years
28 More information can be found in the Appendix C
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until it drops off completely in the late 2030s. MRW’s forecast of the residential PCIA charge
through 2030 is summarized in Table 4.
Table 4. PG&E Residential PCIA Charges, ¢/kWh (nominal)
2015 2018 2020 2025 2030
2.3 2.5 2.2 1.1 0.9
Pro Forma Elements and CCA Costs of Service
MRW conducted a pro forma analysis to evaluate the expected financial performance of the
CCA and the CCA’s competitive position vis a vis PG&E. The analysis was conducted on a
forward looking basis from the expected start of CCA operations in 2017 through the year 2030,
with several scenarios considered to address uncertainty in future circumstances.
Pro Forma Elements
Figure 13 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 Alameda County CCA customers and the generation-related
costs that would be paid by PG&E bundled service customers. Costs paid by CCA customers
include all CCA-related costs (i.e., supply portfolio costs, net energy efficiency costs,29 and
administrative and general costs) and exit fee payments that CCA customers will be required to
make to PG&E.
As discussed in previous sections, supply portfolio costs and energy efficiency program costs are
informed and affected by CCA loads, by the requirements the CCA will need to meet (or will
choose to meet) such as with respect to renewable procurement, and by CCA participation levels,
which can vary depending on whether or not all cities in the county choose to join the CCA.
Administrative and general costs are discussed further below.
29 We anticipate that Alameda County CCA’s energy efficiency costs will be fully offset by Public Benefits Charge
revenue provided by PG&E for the purpose of energy efficiency programming and that net costs to Alameda County
CCA will be zero.
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Figure 13. Pro forma Analysis
Inputs: selection of scenarios and cities
Load
Forecast
PG&E
Generation Rate
Forecast
Supply Costs
Forecast
Adm. Costs
Forecast
Assessment of CCA viability and CCA customer rates vs, PG&E customer rates
(also accounts for reserve fund contributions)
Exit fees
Forecast
Net Energy
Efficiency Costs
Forecast
Generation Rates paid by Alameda County CCA Customers
(also accounts for debt interest)
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Startup Costs
Table 5 shows the estimated CCA startup costs. They are based on the experience of the existing
CCAs as well as from other CCA feasibility assessments.
Table 5. 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 $1,000,000
Consultants and Legal Counsel $500,000
Marketing & Communications $500,000
PG&E Service Fees $75,000
CCA Bond $100,000
Miscellaneous $500,000
Total $ 3,300,000
Working Capital $51,000,000
Total $54,300.000
Working capital is set to equal three months of CCA revenue, or approximately $50 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 by a bank on credit to the CCA. 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.
Energy Efficiency Program Costs
CCA’s have the opportunity use both electric and gas public purpose program funds to provide
energy efficiency programs to customers, and using rules defined in CPUC Ruling R.09-11-014
and various cost reports.30As discussed in Chapter 7, approximately $3.9 million would be
available for programs administered by a CCA to Alameda County residents, including both
30 Electric and Gas Utility Cost Report. Public Utilities Code Section 913 Report to the Governor and Legislature,
April 2016.
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CCA and PG&E customers, or $3.5 million if these programs serve only CCA customers,
assuming a 15% opt-out rate. This latter case was modeled.
Administrative and General Cost Inputs
Administrative and general costs cover the everyday operations of the CCA, 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 CCAs to develop
estimates of the costs that would be faced by an Alameda County CCA. Administrative and
general costs are phased in from 2017 to 2019, as the CCA 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 CCA 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 CCA costs and the rates that would need to be charged to CCA customers
to cover these costs, MRW summed the three categories of CCA costs (i.e., supply portfolio
costs, net energy efficiency 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 CCA loads to
develop the average rate the CCA would need to charge customers to cover its costs (“minimum
CCA rate”).
To establish the Alameda County CCA rate, MRW adjusted the minimum CCA rate, if needed,
based on the competitive position of the CCA. In particular, when the total CCA customer rate
(i.e., the minimum CCA rate plus the PG&E exit fee) was below the projected PG&E generation
rate,31 MRW increased the minimum CCA rate up to the amount needed to meet the reserve
refund targets while still maintaining a discount. MRW used the surplus CCA revenue from
these rate increases (“Reserve Fund”) in order to maintain Alameda County CCA
competitiveness with PG&E rates in years in which total CCA 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 Alameda County CCA 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.
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 18 MRW & Associates, LLC
Chapter 3: Cost and Benefit Analysis
As described in the prior chapter, as part of the pro forma analysis, MRW calculated Alameda
County CCA rates that would, where feasible, cover CCA costs and maintain long-term
competitiveness with PG&E. This chapter uses those rates to compare the costs and benefits of
the Alameda County CCA across three scenarios: (1) Renewable Compliance, (2) Accelerated
RPS and (3) 80% RPS by 2021. Costs and benefits are evaluated by comparing total CCA
customer rates (including PG&E exit fees) to PG&E generation rates to assess the net bill
savings (costs) for customers that join the CCA.
Scenario 1 (Renewable Compliance)
Under Scenario 1, the Alameda County CCA meets all RPS requirements (including Senate Bill
350 requirements) and does not obtain incremental renewable power or low-carbon power in
excess of these requirements.
Rate Differentials
Figure 14 summarizes the results of this scenario in the form of the total Alameda County CCA
customer rate (vertical bars) and the comparable PG&E generation rate (line).33 Of the CCA cost
elements, the greatest cost is for non-renewable generation followed by the cost for the
renewable generation, which increases over the years according to the RPS standards. Another
important CCA customer cost is the PCIA exit fee, which is expected to decrease in most years
beginning in 2019 and to become less important over time.
Under Scenario 1, the differential between PG&E generation rates and Alameda County CCA
customer rates is positive in each year (i.e., CCA rates are lower than PG&E rates). As a result,
Alameda County CCA 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. The annual differential between the PG&E rate and the total CCA customer rate is expected
to vary significantly over the course of this period (Figure 14). During the initial period from
2017-2023, the differential between the two rates increases (i.e., the CCA becomes more cost-
competitive) due to an expected decrease in the exit fees charged to Alameda County CCA
customers. 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 at a modest rate as PG&E’s generation
rates stabilize and exit fees decline.
33 All rates are in nominal dollars
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 19 MRW & Associates, LLC
Figure 14. Scenario 1 Rate Savings, 2017-2030
Residential Bill Impacts
Table 6 shows the average annual savings for Residential customers under Scenario 1. The
average annual bill for the residential customer on the Alameda County CCA program will be on
average 7% lower than the same bill on PG&E rates.
Table 6. Scenario 1 Savings for Residential CCA Customers
Residential
Monthly
Consumption
(kWh)
Bill with PG&E
($)
Bill with
Alameda
County CCA ($)
Savings ($) Savings (%)
2017 650 147 142 5 3%
2020 650 160 145 15 9%
2030 650 201 188 13 6%
Greenhouse Gas Emissions
Figure 15 shows the GHG emissions from 2017-2030 for Alameda County CCA under Scenario
1, and PG&E’s expected emissions for the same load if no CCA is formed. The CCA’s GHG
emissions initially increase from 2017 to 2019 as the CCA is phased in across the county (from
serving 33% potential county load in 2017 to 100% in 2019), and then decrease steadily in the
following years as the CCA’s renewable content grows pursuant to SB 350’s requirements of
50% RPS by 2030. PG&E emissions are lower than those of the CCA in this scenario due to the
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 20 MRW & Associates, LLC
diversity in PG&E’s electric mix. Besides renewable generation, over 40% of PG&E’s supply
portfolio is made up of nuclear and large hydro generation, both of which are emissions-free
generation technologies. PG&E’s GHG emissions decrease before 2019 and increase between
2019 and 2024 due to the changes in its RPS procurement.34 In 2025, the retirement of the
Diablo Canyon nuclear generation plant increases PG&E’s GHG emissions by approximately
30% as the utility will need to increase its fuel-fired generation to make up for the loss. In the
following years PG&E’s GHG emissions are expected to decrease as it ramps up renewable
procurement to meet its mandated RPS goals.
Figure 16. Scenario 1 GHG Emissions by Year (“Normal” PG&E Hydro Conditions)
Scenario 2 (Accelerated RPS)
Under Scenario 2, Alameda County CCA meets 50% of its load through renewable power
starting from 2017, while 50% of its non-renewable load is met through hydro-electricity.
Rate Differentials
Figure 17 summarizes the results for this scenario, with the vertical bars representing the
Alameda County CCA customer rate and the counterpart PG&E generation rate shown as a line.
34 According to the PG&E RPS plan PG&E Final 2015 Renewable Energy Procurement Plan, filed in CPUC
proceeding R.15-02-020, January 14, 2016, Appendix D, Table 2 and Table 4, the RPS procurement in 2019-2024
falls in average 3.5% annual.
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 21 MRW & Associates, LLC
In this scenario, the renewable lost is the largest single element of the CCA rate, reflecting the
higher renewable content of this scenario. Non-renewable generation is the next largest cost
component of the rate, followed by the PCIA exit fee. The PCIA exit fee is expected to decrease
in most years beginning in 2019, as it did in the case of Scenario 1. However, the costs
associated with GHG allowance purchases are a lower portion of the total costs in this scenario
because 50% of the non-renewable generation is expected to be met by hydro-electricity, which
is a non-emitting resource. This limits the need for purchase of GHG allowances.
The differential between PG&E generation rates and Alameda County CCA customer rates in
Scenario 2 is lower than that under Scenario 1; however, it continues to follow a similar pattern
over the years with respect to PG&E rates, and it is positive in all years from 2017 to 2030. As
was the case under Scenario 1, because of this positive differential, Alameda County CCA
customers’ average generation rate (including contributions to the reserve fund) can be s et at a
level that is lower than PG&E’s average customer generation rate in each year under this
scenario as well.
Figure 17. Scenario 2 Rate Savings, 2017-2030
Residential Bill Impacts
Table 7 below shows the average annual savings for residential customers under Scenario 2. The
annual bill for a residential customer on the Alameda County CCA program will be for the
period 2017-2030 on average 6.5% lower than the same bill on PG&E rates. This is lower than,
but close to, bill savings under Scenario 1.
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 22 MRW & Associates, LLC
Table 7. Scenario 2 Savings for Residential CCA Customers
Residential
Monthly
Consumption
(kWh)
Bill with PG&E
($)
Bill with
Alameda
County CCA ($)
Savings ($) Savings (%)
2017 650 147 146 1 1%
2020 650 160 147 13 8%
2030 650 201 188 13 6%
GHG Emissions
The Alameda County CCA’s GHG emissions under Scenario 2 are much lower than those under
Scenario 1. This is due to the higher renewable content in the CCA’s generation mix under
Scenario, as well as the 50% hydro content in the non-renewable generation mix.
Figure 18 compares the GHG emissions from 2017-2030 for the Alameda County CCA under
Scenario 2 with what PG&E’s emissions would be for the same load if no CCA is formed. The
Alameda County CCA’s emissions increase from 2017 to 2019 as the CCA is phased in across
the entire county, and then remain flat through 2030. PG&E’s GHG emissions are initially
slightly lower than the CCA’s emissions, but as the CCA’s emissions flatten out, PG&E’s
emissions follow a generally upward trend and surpass CCA emissions in 2024, with the
expected retirement of Diablo Canyon in 2025 – further bumping up PG&E’s emissions by
approximately 30% in 2025. Following this, PG&E’s emissions are expected to decrease from
2026 to 2030 as PG&E procures renewables to meet its mandated RPS goals. However, they still
remain higher than the CCA’s expected GHG emissions.
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 our PG&E emissions are
the PG&E emissions shown here are lower that the “current” emission. 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, resulting in GHG savings for
Scenario 2 rather than parity.
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July, 2016 23 MRW & Associates, LLC
Figure 18. Scenario 2 GHG Emissions by Year (“Normal” PG&E Hydro Conditions)
Scenario 3 (80% RPS by 2021)
Scenario 3 is the most aggressive scenario considered, in terms of renewable procurement. Under
this scenario, the Alameda County CCA starts with 50% of its load being served by renewable
sources in 2017, and increases this at a quick pace to 80% of its load being served by renewable
sources in 2021. In addition, 50% of its non-renewable supply is met through large hydro-electric
sources.
Rate Differentials
Figure 19 summarizes the rates for the Alameda County CCA under Scenario 3 from 2017 to
2030, and also shows PG&E’s expected generation rate for comparison. Under this scenario, the
costs for renewables form the largest component of the CCA’s rates, and grows steadily to
account for nearly 60% of the total CCA rate in 2019, and then nearly 70% of total CCA rate by
2030. Non-renewable generation is the next largest cost component of the rate, followed by the
PCIA exit fee. The PCIA exit fee is expected to decrease in most years beginning in 2019, as it
did in the case of Scenarios 1 and 2. As with Scenario 2, the costs associated with GHG
allowance purchases are a lower portion of the total costs in this scenario because 50% of the
non-renewable generation is expected to be met by hydro-electricity, which is a non-emitting
resource. However, as the renewable content increases and the non-renewable content decreases,
the need for purchase of GHG allowances is further lowered, making the GHG costs an even
smaller component of the total rate.
The differential between PG&E generation rates and Alameda County CCA customer rates in
Scenario 3 is the lowest of the three scenarios, as this scenario has the most expensive supply
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July, 2016 24 MRW & Associates, LLC
portfolio. However, the expected Alameda County CCA rates continue to be lower than expected
PG&E generation rates for all years from 2017 to 2030. Though this positive differential still
allows for the collection of reserve fund contributions through the CCA’s rates in all the years
under consideration, between 2026 to 2028 the differential is very small.
Figure 19. Scenario 3 Rate Savings, 2017-2030
Residential Bill Impacts
Table 8 below shows the average impacts on the bills of residential customers under Scenario 3.
The annual bill for a residential customer on the Alameda County CCA program will be on
average 3% lower (over the 2017-2030 study period) than the same customers on PG&E rates,
under this scenario.
Table 8. Scenario 3 Savings for Residential CCA Customers
Residential
Monthly
Consumption
(kWh)
Bill with PG&E
($)
Bill with
Alameda
County CCA ($)
Savings ($) Savings (%)
2017 650 147 146 1 1%
2020 650 160 154 6 4%
2030 650 201 196 5 2%
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July, 2016 25 MRW & Associates, LLC
GHG Emissions
Similar to Scenarios 1 and 2, under Scenario 3, the Alameda County CCA’s GHG emissions first
increase from 2017 to 2019 as the CCA is phased in into the entire county. However, in Scenario
3 this increase is partially off-set by the increasing renewable content in the CCA’s supply mix.
Thus the CCA’s emissions in this scenario grow at a slower rate from 2017 to 2019 than in the
first 2 scenarios, then decrease till 80% renewable supply is achieved in 2021, and remain flat
thereafter. The CCA’s GHG emissions under this scenario are lower than PG&E’s expected
emissions for the same load if no CCA is formed. Figure 20 shows the expected GHG emissions
from the CCA and PG&E for all years from 2017 to 2030.
Figure 20. Scenario 3 GHG Emissions by Year (“Normal” PG&E Hydro Conditions)
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 26 MRW & Associates, LLC
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
Alameda County CCA’s feasibility 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 Alameda County CCA customers.35
The base-case analysis (Chapter 3 –Scenario 1) was developed as a reasonable and conservative
assessment of the Alameda County CCA. In addition to the base case analysis, MRW analyzed
alternative cases to address six risks: (1) the relicensing of the Diablo Canyon nuclear units, (2)
higher renewable supply costs, (3) higher PCIA charges, (4) higher natural gas prices, (5) lower
PG&E portfolio costs, and (6) a combination of the last four of these five risks (stress scenario).
Diablo Canyon Relicensing Sensitivity
In the base case the Diablo Canyon nuclear units are retired at the end of their current operating
licenses (Unit 1 in 2024 and Unit 2 in 2025).36 At this time, nuclear retirement appears to be the
lower-cost option for PG&E ratepayers given, on the one hand, low market prices for
replacement power (both gas-fired and renewable) and, on the other hand, the significant costs
PG&E would likely incur to undertake a cooling system modification and potentially other
upgrades that would be required to relicense the plant and continue operations.37 Under the
relicensing scenario, PG&E’s generation rate would therefore increase, providing a competitive
benefit to the Alameda County CCA.38 As shown in Table 8, MRW anticipates that the average
rate differential over the 2017-2030 period would increase by 1.35¢/kWh under the Diablo
Canyon relicensing scenario.
35The Alameda County CCA rate includes the PG&E exit fees (PCIA charges) that will be charged to CCA
customers but does not include the rate adjustment for the reserve fund.
36 This assumption is consistent with the CPUC’s proposed assumptions fo r long-term transmission planning.
“Administrative Law Judge’s Ruling Seeking Comment on Assumptions and Scenarios for use in the California
Independent System Operator’s 2016-17 Transmission Planning Process and Future Commission Proceedings,”
CPUC proceeding R.13-12-010, February 8, 2016, page 41.
37 The new cooling system, which would be required per state regulations implementing the Federal Clean Water
Act, Section 316(b), would have an estimated cost of $4.5 billion. Subcommittee Comments on Bechtel’s
Assessment of Alternatives to Once-Through-Cooling for Diablo Canyon Power Plant. November 18, 2014, page
10.
38 An increase in PG&E’s rates results in an increase to the CCA customers’ exit fees (which pay for the above -
market costs of PG&E’s rates). However, this exit fee increase is much smaller than the PG&E rate increase, and the
relicensing scenario provides an overall benefit to the CCA.
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July, 2016 27 MRW & Associates, LLC
Table 9. Diablo Canyon Relicensing Sensitivity Results, 2017-2030
Average PG&E
Rate (¢/kWh)
Average Rate
Differential (¢/kWh)
Base Case 10.36 2.1
Diablo Canyon Relicensing 11.75 3.4
Higher Renewable Power Prices Sensitivity
This sensitivity case evaluates the impact of higher prices for renewable power on the CCA’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.39,40 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 CCA and PG&E, but they have
a greater effect on the CCA because PG&E has significant amounts of renewable resources
under long-term contract. The impact of this stress case is to reduce the 2017-2030 average rate
differential by 0.3¢/kWh relative to the base case.
Table 10. Higher Renewable Power Prices Sensitivity Results, 2017-2030
Average Renewable
Power Prices
(¢/kWh)41
Average Rate
Differential
(¢/kWh)
Base Case 5.4 2.1
Higher Renewable Power Prices 6.6 1.8
39 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
40 The base case forecast would also be consistent with a scenario in which the tax credit expirations a re delayed.
41 Average for solar and wind utility scale generation (>3MW), not including local Alameda County generation.
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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 2030. This increases the 2030 PCIA to 250% of its base case value. The impact of
this stress case is to reduce the 2017-2030 average rate differential by 0.7¢/kWh relative to the
base case.
Table 11. Higher PCIA Exit Fee Sensitivity Results, 2017-2030
Average PCIA Rate
(¢/kWh)
Average Rate
Differential
(¢/kWh)
Base Case 1.4 2.1
Higher Exit Fees (PCIA) 2.1 1.4
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,42 which is
up to 60% higher than MRW’s base case forecast in some years. Natural gas price increases
affect power supply costs for both Alameda County CCA and PG&E; however, the nuclear and
hydroelectric capacity in PG&E’s resource mix makes PG&E less sensitive than Alameda
County CCA to changes in natural gas prices. The net effect of higher natural gas prices is
therefore to increase CCA rates relative to PG&E rates43 (i.e., reduce the average rate
differential). Under the sensitivity conditions considered, the 2017-2030 average rate differential
decreases relative to the base case by 0.9¢/kWh.
42 U.S. Energy Information Administration. “2015 Annual Energy Outlook,” Table 13
43 For the Scenario 3 the high gas natural prices case is favorable (i.e., the rate differential is higher than the rate
differential for the Base Case).
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July, 2016 29 MRW & Associates, LLC
Table 12. Higher Natural Gas Prices Sensitivity Results, 2017-2030
Average Natural
Gas Price
($/MMBtu)
Average Rate
Differential
(¢/kWh)
Base Case 4.85 2.1
Higher Natural Gas Prices 7.67 1.2
Lower PG&E Portfolio Cost Sensitivity
While changes to natural gas prices and renewable power prices affect both the CCA and PG&E,
dampening the impact on the CCA’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 CCA. 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 2017-2030 average rate differential
would be reduced by 1 cent per kWh relative to the base case scenario.
Table 13. Lower PG&E Portfolio Sensitivity Results, 2017-2030
Average PG&E
Rate (¢/kWh)
Average Rate
Differential
(¢/kWh)
Base Case 10.4 2.1
Lower PG&E Portfolio Costs 9.3 1.1
Stress Case and Sensitivity Comparisons
For all but the Diablo Canyon relicensing case, rate differentials (i.e., the CCA’s competitive
positions) are lower in the sensitivity cases than in the base case scenario, for all years from 2017
to 2030 (Figure 21). To evaluate a more extreme scenario, MRW developed a stress case that
combines all the negative sensitivity cases: (1) higher renewable power prices, (2) lower PG&E
portfolio costs, (3) higher PCIA exit fees, and (4) higher natural gas prices. The 2017-2030
average rate differential for this stress case is negative, at -0.7¢/kWh, meaning that CCA
customer costs would exceed PG&E customer costs under this scenario.
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July, 2016 30 MRW & Associates, LLC
Table 14. Stress Test Results, 2017-2030
Average Rate
Differential
(¢/kWh)
Base 2.1
Stress Scenario -0.7
Figure 21 shows the difference between the PG&E customer rate and the Alameda County CCA
customer rate (including exit fees) in the base case and in each of the sensitivity scenarios, for
each year from 2017 to 2030. As Figure 21 illustrates, CCA customer rates are lower than PG&E
customer rates in each of the individual sensitivity cases in each year and are lower that PG&E
customer rates in the stress test case from 2017-2023. Beginning in 2024, CCA customer rates
exceed PG&E customer rates in the stress test case (i.e., the rate differential is negative) due to
the reduction in PG&E rates as Diablo Canyon is retired and replaced with lower-cost power
sources.
Figure 21. Difference Between PG&E Customer Rates and CCA Customer Rates Under
Each Sensitivity Case, 2017-2030
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July, 2016 31 MRW & Associates, LLC
The results shown above reflect the RPS Compliance supply scenario. MRW additionally
evaluated each sensitivity scenario under the two alternative supply scenarios: (1) Accelerated
RPS and (2) 80% RPS by 2021. Figure 22 depicts the average rate differentials for 2017-2030
for each sensitivity case under the three supply scenarios.
Figure 22. Difference Between PG&E Customer Rates and CCA Customer Rates Under
Each Sensitivity Case and Supply Scenario, 2017-2030 Average
Scenario 1 (RPS Compliance) is the least costly scenario for the CCA and therefore has the
highest rate differential under most of the sensitivity cases considered. Scenario 2 (Accelerated
RPS), though still quite competitive with PG&E, fares slightly worse, with a rate differential
approximately 8% 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 Scenarios 1 and 2 have
about the same results. This is due to the higher renewable content in Scenario 2, which makes
the supply portfolio less susceptible to volatility in natural gas prices than Scenario 1. Scenario 3
(80% RPS by 2021) has the highest renewable content and is the costliest scenario, with rate
differentials much lower than those in Scenario 1 and Scenario 2. Scenario 3 is anticipated to be
competitive with PG&E in most cases (on average); however, the margins are much lower,
particularly in the “High Renewable Prices” sensitivity case, and they become negative in the
“Low PG&E rates” sensitivity case (i.e., CCA customer rates are higher than PG&E rates). On
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July, 2016 32 MRW & Associates, LLC
the other hand, Scenario 3 is relatively unaffected by the “High Natural Gas Prices” sensitivity
case due to the lower share of natural gas power in this supply portfolio.
In the stress case, Alameda County CCA customer rates exceed PG&E customer rates on
average over the 2017-2030 period for all three scenarios, with the rate differential being highest
in Scenario 3 at -1.5¢/kWh. This is double the Scenario 2 stress case rate differential of -
0.75¢/kWh.
Conclusions
Under the base case scenario, Alameda County CCA customer rates compare quite favorably to
PG&E rates in all years from 2017 to 2030, under all three supply scenarios. Furthermore, under
the base supply scenario (RPS compliance), Alameda County CCA customer rates remain below
PG&E rates under all but the most extreme sensitivity case considered. However, under the
alternate supply scenarios, as the CCA renewable content increases, the CCA becomes less
completive with PG&E. This is especially pronounced in the 80%-by-2021 scenario, which
shows marginal or negative competitiveness vis a vis PG&E in a number of scenarios. Under the
stress case, irrespective of the supply scenario considered, CCA rates are higher than PG&E
rates. While the stress case may appear extreme given that it involves four 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 CCA
venture.
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July, 2016 33 MRW & Associates, LLC
Chapter 5: Macroeconomic Impacts
Each of the three scenarios discussed thus far is next examined for job impacts within Alameda
County. To understand just how job impacts can come about, and the extent of those changes
(plus or minus), a brief description of elements associated with the CCA and how they influence
the existing economy is provided.
How a CCA interacts with the Surrounding Economy
The establishment and operation of a CCA creates a new set of spending (also referred to as
demands) elements 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 as a result of retail
rate differentials. Some of these new elements have temporary effects, while others have long-
term effects. Investment in locally situated elements (such as operation & maintenance) will
result in the direct creation of jobs, and when a job is created in a sector, there will be a
multiplier response on “backwardly-linked” jobs with supplier businesses. 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 – [direct jobs, short-term]
New Renewable Operations within County – [direct jobs, long-term]
New Energy-efficiency within County – [direct jobs, short-term]
Net Generating Capacity and Operations offsets for PG&E outside of county –
[direct jobs, short & long-term]
To frame expectations around how many direct jobs can be created in the county from the above
CCA elements, consideration must be given to (a) how much of the spending associated with the
CCA scenario is fulfilled by a within county business or resident workforce, and (b) what do
these locally-fulfilled dollars represent in terms of current annual county business activity, e.g. is
this a large spending event.
Table 15 presents these considerations, which are shaped in part by assumptions defined by the
MRW study team. For instance, the labor share required on the annual investments (or the
operating budget) was assumed to be 100 percent satisfied by within county resident laborers.
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Table 15. Initial Investment within Alameda County from Proposed CCA
2017 to 2030
CCA
Scenario
Local Capture on RE
investments (billion$)
As % of County’s
Total RE
investment
As % of County’s
Expected Economic
Activity
Bill Savings
(billion$)
1 $0.42 44% 0.01% $1.57
2 $0.42 44% 0.01% $1.51
3 $0.45 45% 0.01% $0.52
As can be seen from the table, the initial local investment that would result from building and
operating additional renewable projects in Alameda County between the years 2017 to 2030
represents a very small portion of the County’s total expected economic activity, 44 even
assuming all of the project costs are directed locally (usually 56% of the project costs would be
funneled outside the county due to procurement of equipment from outside the county). By
contrast bill savings for scenarios 1 and 2 provide over three fold the benefits of initial local
investment. These bill savings indirectly stimulate the economy and ultimately create jobs.
Table 16 illustrates this through high-level results expressed as average annual job changes for
the three CCA scenarios. While scenarios 1 and 2 create nearly identical direct jobs (due to
comparable investment in local renewable projects), scenario 1 creates far more TOTAL jobs.
This is due to the higher bill savings under scenario 1. Scenario 3 creates a few more direct jobs,
but far fewer total jobs, due to decreased bill savings as compared to the other two scenarios. As
a result, its total job impact is 55 percent of the scenario 1 total job impact. A more detailed
discussion of these results will follow later.
Table 16. Average Annual Jobs created in Alameda County by the CCA –
Direct and Total Impacts
2017 – to – 2030 County Impacts
CCA
Scenario
Local Capture on RE
investments
(billion$)
Bill Savings
(billion$)
Average
Annual
DIRECT Jobs
Average
Annual
TOTAL Jobs
1 $0.42 $1.57 165 1322
2 $0.42 $1.51 166 1286
3 $0.45 $0.52 174 731
44 Forecast to be $3,500 billion (nominal). Source REMI Policy Insight model, Alameda County forecast.
Community Choice Aggregation Feasibility Analysis Alameda County
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How Job Impacts Are Measured
The scenario-specific elements described in the prior section are expressed as annual dollar
amounts (plus or minus) in comparison to what would have been expected in the county
economy without a CCA. Initially these amounts supplied by MRW and Tierra are general,
representing total project cost by year. The annual investment for specific types of renewable
energy projects and of making further energy-efficiency improvements are really comprised of
some portion spent on installation labor, a large portion for the equipment (either manufactured
in the region or if not, a leakage to imports), and some small portion soft project costs. These
details are necessary for modeling impacts on the county economy due to a CCA program.
A macroeconomic impact (industry) forecasting model of Alameda County45 is used, the dollar
amounts, with further data refinement (detail) are introduced to the model, the economy adjusts
to these spending and savings changes by year and then identifies annual impacts in terms of
dollar concepts (wages, sales, prices, gross regional product) and jobs, among numerous other
metrics. Appendix E provides some high-level background on the REMI Policy Insight model.
This model was chosen since it is uniquely qualified over other models and approaches to
understand how price (or rate) changes on the business segment (Commercial /Industrial energy
customers) influence business activity levels. Since electric rate differentials are a key
consideration in pursuing a CCA, the study required a method that would adequately address
this.
Scenario Results
MRW created the three supply scenarios by considering how much within county RE investment
(for future generating assets) the CCA could fund, and how much it might invest elsewhere in
California (rest of California or “roCA”). Program administration and energy efficiency
deployment investments are the same in all three scenarios. As can be seen from Table 17,
scenario 3 has the most proposed CCA renewables investment within county but, it has the
lowest bill savings. In contrast scenario 1 would site a smaller renewables investment by the
CCA as within county, but has proportionally much higher bill savings.
45 The model is a Policy Insight model by Regional Economic Models, Inc. (REMI) of Amherst, MA. It is a model
that has been used by the CA Energy Commission, CALTrans, Los Angeles MTA, ABAG, City of San Francisco,
and the South Coast AQMD. For this study a two -region socio-economic forecasting model (the county, and balance
of State) with 23- industries was used.
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Table 17. Initial Comparison of Proposed CCA Scenarios
2017 to
2030
Million$
nominal Million $ nominal DEMAND
Scenario Bill
Savings
CCA Renewable
Investment CCA Renewable O&M
PG&E
Offset
Renew.
O&M
Alameda
Co.
rest of
CA
PG&E
offset RE
invest.
roCA
Alameda
Co. rest of CA Alameda
1 $1,574 $623 $1,676 -$1,946 $47 $133 -$153
2 $1,513 $623 $2,217 -$2,446 $47 $190 -$206
3 $522 $674 $2,514 -$2,785 $51 $200 -$219
Note: Customers’ bill savings account for PG&E’s indifference charge, and any out-of-pocket
expenditures for customer-sited renewable or efficiency projects.
Job and Gross Regional Product Total Impacts
The yearly profile for the county’s total impacts – whether as jobs (Figure 23) or dollars of gross
regional product (GRP) (
Figure 24) – shows that scenario 1 outperforms the other two scenarios. All scenarios share the
year 2023 as the year of maximum positive impact which is due to maximum net rate savings.
The cumulative GRP impact through 2030 for scenario 1 represents a 0.12% change relative to
the county’s forecasted GRP without a CCA.
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Figure 23. Alameda County Total Job Impacts by Scenario
Figure 24. Alameda County Total Gross Regional Product Impacts by Scenario
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County Job impact by Stage of Job generation, Scenario 1
Job changes typically start from a direct productive event that alters the need for labor, such as
constructing a facility or opening/closing a business. Then there are the local cycles of business -
to-business supplier transactions that follow (called indirect jobs), cycles of household spending
from the direct and indirect paychecks (called induced jobs), and sometimes there are job
changes due to changes in costs (rates) of a location which affect doing-business in the county.
These are job impacts from competitiveness effects. The indirect and induced combined are
referred to as multiplier effects. The total job impact reflects the direct, the multiplier, and the
competitiveness effects. Figure 25 juxtaposes the county’s direct job impacts with the total job
impacts from Scenario 1. The majority of job creation in the scenario is from non-direct
economic influences - specifically from the net rate savings which drives approximately 76
percent of the county’s job gain (Figure 26). As shown in Appendix E, Scenario 2 would have
an identical profile of direct jobs but a slightly lower total job profile, due to almost $60 million
of curtailed net rate savings (relative to scenario 1) through 2030. Scenario 3 has a slightly
higher direct job profile but a greatly reduced total job impact profile.
Figure 25. CCA Scenario 1 County Job Impacts
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Figure 26. Alameda County CCA Scenario 1 Total Jobs Impacts by Source
County Job Impacts by Sector 2023 (Scenario 1)
The county’s sectors which will create these jobs are shown next in Figure 27. The year 2023 is
selected since it is when the maximum job impact was shown. Not all sectors are involved with
CCA activities (the absence of direct jobs) but all do experience business growth -hence added
jobs- as a result of multiplier effects and competitiveness effects. The per-worker 2023
(forecasted and nominal) earnings rate is shown to the right of the sector name. The average
(weighted) annual earnings implied across the 2,282 jobs gained within the county in 2023 is
$102,120.
The results of the other two Scenarios are found in Appendix E.
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Figure 27. Alameda County Jobs Changes by sector (annual earnings per worker), 2023
Focus on Construction Sector Jobs
The county economy does not forfeit Construction sector jobs (nor does the balance of California
economy). In fact, as Figure 27 shows, Construction experiences the largest direct (136 jobs) and
total job change (440) for 2023 among all sectors. The degree to which any of these jobs are
held by union members or equivalently non-union laborers “working under a collective
bargaining agreement (CBA)” is addressed by understanding the publicly available data sources
that are used in calibrating any region of a REMI model. It should be noted that the REMI
model does not carry a union segmentation on the industry specific employment data. REMI
relies upon data series from the U.S. Department of Labor, Commerce and Census. All the data
products are the result of states providing a mix of annual and quarterly reports. A consistent
characterization of REMI’s Construction sector employment is obtained from (Census’) the
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Current Population Survey – Earnings Report (2014) which for California shows approximately
20 percent of construction employment is engaged in work ‘covered’ by a CBA.46 Again those
working under a CBA need not all be union members. The Construction sector activity in the
two-region REMI model is therefore a blend of work, (20:80) covered-to-non-covered projects.
Table 18shows average annual direct and total job impacts by scenario and how many occur in
the Construction sector and which would be “covered” by a CBA. Because the direct
construction jobs (in particular) vary markedly from year to year (depending upon if a generation
project is under construction or not, it is informative to look at a single year). Table 19 shows the
construction jobs in 2023, the peak year for direct construction activity. As the table shows,
when a project is utility-scale is under construction, the construction jobs increase to about ten
times the average number.
Table 18. County’s Average Annual Construction Job Impacts
Scenario
Jobs in All Sectors Jobs in Construction Sector Jobs Associated with CBA
Direct Total Direct Total Direct Total
1 165 1322 80 235 16 47
2 166 1286 81 231 16 46
3 174 731 86 160 17 32
Table 19. Peak-Year Construction Job Impacts
CCA
Scenario
Jobs in Construction Sector Jobs Associated with CBA
Direct Total Direct Total
1 136 440 27 88
2 137 432 27 86
3 154 326 31 65
The CBA distinction is important as it uses the prevailing hourly wage set by the CA Dept. of
Industrial Relations47 for public-funded projects. It is premature to determine how much of the
46 www.unionstats.com
47 See page 49 of http://www.dir.ca.gov/oprl/pwd/Determinations/Northern/Northern.pdf
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proposed CCA renewable capacity in any of the scenarios would indeed be public-funded (as
opposed to power purchase agreements with third party private project developers). The straight-
time48 prevailing hourly “covered” wage rate for FY2016 in the northern counties (including
Alameda County) for Group 3 construction laborers is $49.74 which is 21 percent higher than the
market rate (indicative of the aforementioned 20:80 blend) of $40.96 in the REMI model.
A sensitivity run (Table 20) was conducted just for the macroeconomic impacts that considers
100 percent union or “covered” labor for the direct effect only. This did not require MRW to
inflate the renewable project costs and then recalculate forecasted CCA electric rates as would be
warranted. Instead – for scenario 1- the fixed (NREL JEDI model derived) labor share on
MRW’s initial annual renewable investment would hire fewer but better paid (by 21 percent)
construction laborers. As Table 20 shows, the prevailing wage sensitivity has 13 fewer average
annual direct (Construction) jobs but the gain in direct “covered” jobs means 51 construction
laborers would be paid more.
Table 20. Scenario 1 Sensitivity on Direct Construction Requirements
Market Wage
(20% covered: 80% not covered)
Prevailing Wage
(100% covered)
Scenario Direct Jobs 165 152
As Construction 80 67
UNION (Covered) 16 67
Non-UNION 64 0
Market Wage
(20% covered: 80% not covered)
Prevailing Wage
(100% covered)
Scenario Total Jobs 1343 1321
As Construction 235 221
UNION (Covered) 47 98
Non-UNION 188 123
The other approach to testing this sensitivity would entail inflating the annual investment cost on
renewable projects by the 21 percent labor premium, restating a higher set of CCA electric rate
projections (from these renewable capacity additions) than the current report is based upon,
leading to a reduced ‘rate savings’ effect. This would more drastically dampen the
macroeconomic impacts than shown in Table 20since the net rate savings have been shown to
account for 76 percent of the county’s positive job impacts.
48 Current Employer Statistics data for 2014 show on average a 40-hour work week in the Construction sector.
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Occupation Impacts for Alameda County, 2023
Sectors that experience job changes will mean changes over a mix of their occupational
requirements. For the maximum year of county job impact, 2023, the broad category
occupational impacts are presented in Figure 28 for Scenario 1 as relates to the direct jobs and
the non-direct jobs (direct plus non-direct equals the total jobs). They are shown in ascending
order of direct stage occupational requirements. It should not be surprising that the non-direct
stage of economic stimulation for the county creates a more pronounced set of occupational
opportunities due to the magnitude of net rate savings benefitting all customer segments within
the county. Note Military and Farming occupations are omitted due to zero or very small
response in both stages of job generation.
Figure 28. Occupational Impacts Scenario 1, 2023
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Chapter 6: Other Risks
Aside from the risks identified above, the CCA or the political jurisdictions that are part of the
CCA could be at risk. This section addresses some of those risks.49
Financial Risks to CCA Members
A CCA is effectively an association of various political subdivisions. The formation documents
for the CCA define the rights and responsibilities of each member of the CCA. Given the large
number of political subdivisions that might participate in an Alameda County CCA, MRW
assumes that the Alameda County CCA would be formed under a Joint Powers Authority, in
much the same way as MCE Clean Energy and Sonoma Clean Power.
The CCA 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 CCA
will take on such financial obligations, it is likely very important to the prospective member
political subdivisions that the financial obligations of the CCA cannot be assigned to the
members.
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
CCA (unless a member agency chooses to bear such obligations). The CCA should obtain
competent legal assistance when developing the formation documents.50
Procurement-Related Risks
Because a CCA is responsible for procurement of supply for its customers, the CCA 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 CCA must be mindful of the
potential competition from PG&E. As a result, the CCA’s portfolio must be both flexible while
meeting the needs of its customers.
The CCA will likely need to negotiate a flexible supply arrangement with its initial set of
suppliers. Such an arrangement is important since the CCA’s loads are highly uncertain during
CCA ramp-up. Without such an arrangement, the CCA 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 CCA’s customers to major purchases or
sales in the spot markets. These spot purchases could have a major impact on the CCA’s
financials.
49 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 C CA will be established.
50 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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The CCA 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 CCA must be mindful that such volatility could increase the need
for reserve funds to help buffer rate volatility for the CCA’s customers. Funding such reserve
funds could be challenging in this time of low gas prices (resulting in high PCIA charges).
The CCA 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 CCA could face stiff competition for renewable supplies, meaning that the green
portfolio costs for the CCA 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
resources owned or controlled by the CCA). This could force the CCA to acquire greater levels
of renewable supplies, thereby increasing costs.
Legislative and Regulatory Risks
As noted above, the CCA 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.51
Additional rules and requirements might be established. These could affect the bottom line of the
CCA.
PCIA Uncertainty
Assembly Bill 117, which established the CCA 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 CCA service. This has been broadly interpreted by the CPUC to
mean that the departure of customers to CCA service cannot cause the rates of the remaining
utility “bundled” customers to go up. In order 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 CCA customers. The PCIA is intended to ensure that generation costs incurred by
PG&E before a customer transitions to CCA 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.
51 Rules to establish RPS requirements under the new 50% RPS mandate are currently being de bated at the CPUC.
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Current CCAs 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 CCA service to be economically
better off (i.e., pay less for electricity), the sum of the CCA 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 CCA can actively monitor and vigorously
participate in CPUC proceedings that impact cost recovery and the PCIA.
Impact of High CCA 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 CCA customers. As such, the PCIA is not affected by the number of
DA/CCA customers.
Currently, for bundled customers the rate impacts associated with fluctuating PCIAs are
relatively small, but this will change as the number of DA/CCA 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 a utility with flat RPS costs, this would have increased the RPS-related PCIA, which would
have reduced 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/CCA 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 CCA Penetration Low-Carbon Resources
Virtually all the CCAs forming in California include carbon reduction as a goal. As the analysis
has shown, CCAs will likely need to purchase carbon-free both qualifying renewables and other,
to meet their goals. This increased demand for carbon-free power will change the “supply-
demand” balance and in theory increase the cost of these resources. To address this risk, the
Alameda County CCA 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.
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Bonding Risk
Pursuant to CPUC Decision 05-12-041, a new CCA 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 CCA were to suddenly fail and be forced to return all its customers back
to PG&E bundled service. Currently, a bond amount for CCAs 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 CCAs
(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 CCA 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
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 CCAs, during normal conditions, the CCA 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 CCA 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: Other Issues Investigated
Funding, Costs, and Impacts of the Energy Efficiency Program Scenario
Having established that both adequate economic and market potential exist beyond what is
currently being targeted through PG&E programs, the MRW Team estimated how much
efficiency could reasonably be captured by assessing the availability of funding for energy
efficiency, and the cost of to acquire it through various programs. Understanding available
funding options and costs allowed the MRW team to determine the amount of energy efficiency
that could be acquired in various funding options and use this to calculate the economic inputs
for the REMI model.
To assess funding, CCA’s have several funding options, including;
Funds from Non-bypassable Electric Charges – CPUC Ruling R.09-11-014 defined various
funding options for CCAs that are administrators of energy efficiency programs, and also
outlined some of the funding authorities available to CCA’s that elect to not administer
programs
Funds from Non-bypassable Gas Charges – CPUC Decision D.14-10-046 allows CCA’s to
administer programs that include funds collected from natural gas customer. This analysis
did not estimate the value of these funds.
Income from CCA Operations. Income generated through CCA operations may be used to
fund customer programs.
Funding secured by aligned organizations, such as StopWaste’s Energy Council, on behalf of
a CCA.
Increased funding through the expansion of the CCA territory. Under current regulations it is
allowed for a CCA to define its service territory more broadly than a city or county. As such,
the rules that define the funding for Alameda County residents would apply to new
participants in a CCA and so provide incremental program funding. For example, in 2015
Marin Clean Energy began serving customer in Contra Costa County and has increased its
available program funding as a result of this enrollment.
This analysis only considered the impact of Non-bypassable Electric Charges. Using rules
defined in CPUC Ruling R.09-11-014 and various cost reports52, Table 21 shows that
approximately $3.9M would be available for programs administered by a CCA to Alameda
County residents, including both CCA and PG&E customers, or $3.5M if these programs serve
only CCA customers, assuming a 15% opt-out rate.
52 Electric and Gas Utility Cost Report. Public Utilities Code Section 913 Report to the Governor and Legislature,
April 2016.
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Table 21. Annual Funding Models for Non-bypassable Electric Charges
Annual Funding Models for Non-bypassable
Electric Charges
Estimated Value
Program Administrator - CCA and PG&E customers $3,941,000
Program Administrator - CCA customer only $3,350,000
The cost of energy was determined by analyzing the 2015 PG&E portfolio to identify the costs
per first year net kWh for programs that are likely to be the most representative of programs
administered by an Alameda County CCA. An analysis the PG&E portfolio, including the
programs presented in Table 22, indicates that $0.61 per net first year kWh is a reasonable
estimate of the current unit cost of energy efficiency.
Table 22. Select Unit Costs for Energy Efficiency ($/ net kWh)
Program
Administrator Sub-Program Name
Percent Program
Savings that are
Electric
Cost Per First Year
Net kWh
Equivalent
PG&E Commercial Energy Advisor 18% $0.18
MCE MEA 02 - Small Commercial 79% $0.37
PG&E Lighting Programs Total 100% $0.38
MCE MEA01 2013-14 MF - Multifamily 36% $0.59
PG&E East Bay 93% $0.59
Third Party RightLights 100% $0.75
PG&E Energy Savers 100% $0.81
Third Party Energy Fitness Program 100% $0.84
The MRW teams defined the level of energy efficiency input into the REMI model by dividing
the available funding by the units cost of energy efficiency as defined above, using the following
assumptions;
Available annual budget for energy efficacy programs is based on the maximum funding
equation provided in R.09-11-014, and assuming programs are administered only to CCA
customers. As discussed in Table 21, this represents approximately $3.5M annually.
The cost of energy efficiency programs most likely to be offered under and a CCA would be
$0.61 per net first year kWh.
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The savings from energy efficiency during the forecast horizon would grow at a rate
consistent with expected annual energy demand as defined in the 2015 CEC IEPR demand
forecast.53
Demand savings would be consistent with the ratio of demand to energy savings achieved by
the programs most likely to be offered by a CCA as presented in Table 22.
Based on this methodology, Table 23 provides a summary of model energy and demand savings
inputs. Note that these savings numbers are incremental to PG&E goals, which average about 42
GWh annually from 2021 through 2024, as defined in the CPUC potential model, which has a
forecast horizon ending in 2024.
Table 23. Model Energy and Demand Savings Inputs
Year 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Annual incremental energy
savings (GWh) 5.7 5.8 5.9 5.9 6.0 6.0 6.1 6.1 6.2 6.3
Annual incremental demand
savings (MW) 0.9 0.9 0.9 0.9 0.9 1.0 1.0 1.0 1.0 1.0
“Minimum” CCA Size?
MRW’s analysis above assumed that all eligible Alameda County cities join the Alameda
County CCA program with a participation rate of 85% from each city, resulting in an anticipated
CCA load of about 7 million MWh per year.54 If fewer customers join, CCA rates will generally
be higher because about $8 million of annual CCA costs are invariant to the amount of CCA
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 competiveness of the CCA, while a
higher share of commercial customers or industrial customers would weaken the competitiveness
of the CCA. Since cities vary in their distribution of customers by rate class, a city opting out of
the CCA could affect the competitiveness of the CCA due to both the reduction in CCA load and
the shift in customer make-up.
The “minimum” load needed for CCA customer rates to be no higher than PG&E customer rates
is approximately 450,000 MWh per year, assuming the average customer portfolio for Alameda
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 CCA’s rates were equal to PG&E’s. As shown in the Figure 29, this is
roughly the load from each of the medium-sized cities (e.g., Pleasanton and San Leandro) and
much smaller than the load from the larger cities (e.g., Berkeley, Oakland, and Fremont). As
53 Form 1.1 - PGE Planning Area California Energy Demand 2015 Revised - Mid Demand Case. Electricity
Consumption by Sector (GWh)
54 In the alternate supply scenarios, the “minimum” annual load assuming the average customer portfolio for
Alameda County and the base case is 550,000 MWh (Scenario 2) and 1,000,000 MWh (Scenario 3). These
“minimum” loads are also far below the expected annual CCA load of 7 million MWh.
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long as two medium-sized cities or one larger city joins the CCA, 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.
Figure 30. Potential load (85% participation) per city
Table 24. Examples of Combinations of Cities and the Average Generation Rate
Examples of city combinations
ONLY BERKELEY ONLY PLEASANTON ONLY DUBLIN +
NEWARK
TOTAL
ALAMEDA
COUNTY
Potential
Load
(MWh)
Customer
Class (%)
Potential
Load
(MWh)
Customer
Class (%)
Potential
Load
(MWh)
Customer
Class (%)
Customer
Class (%)
Residential 136,000 23.37% 158,000 35.11% 160,000 33.83% 32.90%
Commercial 176,000 30.24% 232,000 51.56% 234,000 49.47% 43.70%
Industrial 74,000 12.71% 36,000 8.00% 41,000 8.67% 13.80%
Public 193,000 33.16% 19,000 4.22% 35,000 7.40% 8.60%
Street lights + Pumping 3,000 0.52% 5,000 1.11% 3,000 0.63% 1.00%
TOTAL 582,000 450,000 473,000
Average PG&E rate (¢/kWh) 9.71 10.56 10.51 10.36
Average CCA rate (¢/kWh) 9.92 10.48 10.19 8.28
Differential rate (¢/kWh) -0.21 0.08 0.32 2.08
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 52 MRW & Associates, LLC
Individuals and Communities Self-Selecting 100% Renewables
The existing CCAs all offer customers an option to choose to receive 100% of their power from
renewable resources in exchange for a rate premium. However, each CCA’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 CCA
customers—on the order of a few percent—have selected the 100% green rate option.
Table 25. CCA 100% Green Rate Premiums
CCA 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
Potential Alameda Co. CCA TBD ~1.5¢/kWh
Any full renewable pricing option offered by the Alameda County CCA would have to be set by
the CCA’s management. The value shown in Table 25, ~1.5¢/kWh, is the average incremental
cost of green power used in the CCA supply assessment (Scenario 2) over the study period.
(Initially, it would have to be ~1.9¢/kWh.) Thus the actual number of hypothetical customers
selecting the rate would not impact the economics of the CCA customer who remain on the
standard rate.
Representatives from at least two communities, Berkeley and Albany, have
expressed interest in having their residents and businesses default onto a 100%
renewable rate. If priced at the cost of incremental renewables, such as is assumed
in Table 25, then there would be no financial impact on the CCA or its remaining
customers. Nonetheless, it could have implications:
Separate CCA 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 CCA, 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
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 53 MRW & Associates, LLC
green community, the billing system would need to know to default them on a
different rate schedule than a customer in a different CCA community. This may
or may not be an issue.
Competition with a PG&E Community Solar Program
PG&E has been offering a solar choice program known as Green Tariff Shared Renewable
Program since February 2015.55 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.56 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 CCA 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 see
PG&E’s Community Solar Program as an immediate threat.
The program is open for enrollment until subscriptions reach 272 MW or January 1, 2019,
whichever comes first.57 While this does limit the ability for PG&E to provide a 100% renewable
option in the long-run, at the start of the CCA this program it provides an opportunity for
customers who desire 100% renewable power to remain with PG&E.
Additional Local Renewables
As noted in Chapter 2, relatively conservative penetrations of locally-sited renewable generation
(solar) was included in the quantitative analysis. Even in scenario 3, the most aggressive with
respect to renewables, the modeling assumed only 175 MW of in-county solar. Other individuals
and studies have placed the potential for solar in the Alameda County at much higher levels. For
example, a 2012 study conducted for Pacific Environment, a San Francisco-Based environmental
non-governmental agency, placed the “technical potential” for rooftop and parking lot PC at over
3,700 MW.58 However, it must be noted that technical potential is different than economic or
achievable potentials; it represented the absolute ceiling on this kind of PV in the county.
Assuming that greater amounts of this solar potential can in practice be tapped has a number of
implications for the results of this study. First, greater local solar will increase CCA costs. As
noted in the supply section of Chapter 2, in-county solar costs about 15% more than solar located
in lower cost, inland counties, and small solar, such as is quantified in the Pacific Environment
55 PG&E website
http://www.pge.com/en/b2b/energysupply/wholesaleelectricsuppliersolicitation/RFO/CommunitySolarChoice.page?
WT.mc_id=Vanity_communitysolarchoice . Accessed 5/16/2016
56 California Public Utilities Commission, Decision 15-01-051, p.3
57 Solar Choice Program FAQs website,
https://www.pge.com/en/myhome/saveenergymoney/solar/choice/faq/index.page Accessed, 5/16/2016
58 Powers, Bill, “Bay Area Smart Energy 2020,” March 2012.
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 54 MRW & Associates, LLC
report, is typically 55% more costly than central solar. This increased cost will narrow the
difference between the rates that the CCA can offer and PG&E. Still, as the analysis has shown,
there is significant financial “headroom” to allow for this.
To explore this, we ran Scenario 2 with the assumption that 50% of the renewables were locally
sourced. This implies that in 2025, there would be about 925 MW small solar (less than 3MW,
including rooftop) and 888 MW large solar in the county (assuming that it can be phased in that
quickly). As shown in Figure 31, the margin between the CCA’s costs (bars) and the projected
PG&E generation rates is much closer than in the standard Scenario 2. This is not unexpected, as
local renewables are assumed to be costlier than large-scale ones located in lower-cost areas of
the state.
Figure 31. Scenario 2 with 50% of the Renewables Met Using In-County Generation
0
2
4
6
8
10
12
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
C$
/
k
W
h
PCIA
GHG
O/M
Non-Renewable
Renewable
PG&E
The impacts on the macroeconomics are more complex. Additional local solar would increase
local direct jobs by employing more workers to install and maintain solar arrays. On the other
hand, the greater driver of jobs, the bill savings from reduced rates, would go down with the
increased CCA costs. While this scenario was not explicitly modeled, the results of the three
scenarios at were model strongly suggest that total economic activity and jobs would decrease
with the inclusion of more local renewables in the CCA’s supply portfolio.
Community Choice Aggregation Feasibility Analysis Alameda County
July, 2016 55 MRW & Associates, LLC
Chapter 8: Conclusions
Overall, a CCA in Alameda County appears favorable. Given current and expected market and
regulatory conditions, an Alameda County CCA should be able to offer its residents and business
electric rates that are a cent or more per kilowatt-hour 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 CCA portfolio (Scenario 3), combined with
other negative factors, do PG&E’s rates become consistently more favorable than the CCAs.
An Alameda County CCA would also be well positioned to help facilitate greater amounts
renewable generation to be installed in the County. While the study assumed a relatively modest
amount for its analysis—about 175 MW, other studies suggest that greater amounts are possible.
Because the CCA 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 CCA in the County than
without it.
The CCA 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 CCA 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. For example, even assuming that the CCA
implements a portfolio with 50% qualifying renewables and contracts with carbon-free
hydropower 50% of the remaining power (i.e., 50% renewable, 25% hydro, 25% fossil/market),
it would only then just barely result in net carbon reductions. However, the extent to which GHG
emissions reductions occur is also a function of the amount of hydroelectric power that PG&E is
able to use. If hydro output (continues) to be below historic normal levels, then the CCA should
be able to achieve GHG savings, (as long as it is also contracting for significant amounts of
carbon-free (likely hydroelectric) power). Therefore, if carbon reductions are a high priority for
the CCA, a concerted effort to contract with hydroelectric or other carbon-free generators would
be needed.
A CCA can also offer positive economic development and employment benefits to the County.
At the peak, the CCA would create approximately 2300 new jobs in the region. The large amount
for be for construction trades, totaling 440 jobs. What may be surprising is that much for the
jobs and economic benefit come from reduced rates; residents, and more importantly businesses,
can spend and reinvest their bill savings, and thus generate greater economic impacts.
Technical Study for Community Choice Aggregation
Program in Alameda County
Addendum:
Greater Local Renewable Development Scenario
Prepared by:
With
MRW & Associates, LLC
1814 Franklin Street, Ste 720
Oakland, CA 94612
Tierra Resource
Consultants
Walnut Creek, CA
Economic Development
Research Group
Boston, MA
July 2016
2
Addendum: Scenario 4 – Greater Local Renewable
Development Scenario
Based on feedback from the Steering Committee, the MRW Team developed a fourth scenario.
This scenario is based on Scenario 2: 50% of its load through renewable power starting from
2017, while 50% of its non-renewable load is met through hydro-electricity (i.e., overall 50%
qualifying renewable. 25% hydro, 25% fossil or market), but with an increased emphasis on in-
county renewable development. For this case, we assumed that one-half of the CCA’s total
renewable requirement would be met by in-county resources by the year 2030.
This constitutes a very aggressive scenario. The amounts of new in-county renewables assumed
are unprecedented, and without a detailed study as to the technical, economic and achievable
penetration of local solar, it should be seen as speculative. As such, the results are more
uncertain than the prior three scenarios. Nonetheless, it points to the possibility that even greater
local economic development benefits and employment if indeed greater local renewable
development can be achieved.
Supply Resources
Figure 1 shows the assumed build-out of new renewable resources under Scenario 4. The local
renewable generation starts in 2017, linearly ramping (80 MW per year) up to 50% of the CCA’s
renewable total by 2030 (900 MW). Consistent with the other scenarios, we considered in-county
renewable generation to consist of small- and utility-scale solar.
At the June 1 Steering Committee meeting, a preliminary version of this scenario was presented.
This final version differs from that preliminary one in two ways. First, the preliminary version
did not assume any phase-in. I.e., 50% local renewables was available at the same rate as CCE
participants phased-in. The final version phases in the new local renewables such that 50% is
ultimately achieved in 2030. Second, the preliminary version assumed that 50% of the TOTAL
load was being met by local renewables, not simply 50% of the renewable component. Thus, the
final Scenario 4 contains less renewables and thus lower costs than the preliminary version
presented at the Steering Committee Meeting.
3
Figure 1. Senario 4 CCA Build-Out
Figure 2 shows the difference on the deployment of the in-county solar generation under
Scenarios 2 and 4. Under Scenario 2 the capacity installed increases on average of 15 MW per
year up to 180 MW, one-fifth the rate of capacity addition under Scenario 4. Furthermore, under
Scenario 4 we assumed a higher fraction of the in-county renewable was met using the small-
scale solar. Under Scenario 2, the ratio of small local solar and large local solar is 2:5, while
under Scenario 4 the ratio is 1:1.
Figure 2. Local Capacity Installed for Scenario 2 and Scenario 4
4
Rate Results
Figure 3 summarizes the results for Scenario 4, with the vertical bars representing the Alameda
CCA customer rate and the counterpart PG&E generation rate shown as a line. As with the other
cases, under the renewable prices assumed in the analysis, the Alameda CCA costs are
consistently less than the PG&E rate.
In Scenario 4, the renewable cost is the largest single element of the CCA rate, reflecting the
high renewable content of this scenario (50% RPS) and, in special, the important share of in-
county renewable generation. Non-renewable generation is the next largest cost component of
the rate, followed by the PCIA exit fee.
Figure 3. Scenario 4 Rate Savings, 2017-2030
Figure 4 shows the Alameda CCA customer average generation rate for Scenarios 2 and 4. As
seen in this figure, the difference on the generation rate between the two scenarios is minimal
during the first years of Alameda CCA operations (when local renewable content is still low), but
it grows rapidly, ultimately resulting in 6% difference by 2030 (rates for Scenario 4 higher than
Scenario 2). This increase is due to the assumed premium for in-county renewable generation,
($20/MWh on average).
5
Figure 4. Scenarios 2 and 4 CCA Rates, 2017-2030
Table 1 below shows the average annual savings for residential customers under Scenario 4. The
annual bill for a residential customer on the Alameda CCA program will be for the period 2017-
2030 on average 5.7% lower than the same bill on PG&E rates. This is lower than, but close to,
bill savings under Scenario 1.
Table 1. Scenario 4 Savings for Residential CCA Customers
Residential
Monthly
Consumption
(kWh)
Bill with PG&E
($)
Bill with
Alameda CCA
($)
Savings ($) Savings (%)
2017 650 147 146 1 1%
2020 650 160 148 12 8%
2030 650 201 192 9 4%
Because the net generating composition of Scenario 4 is the same as Scenario 2, the greenhouse
gas emissions would be approximately the same.
6
Macroeconomic Impacts
As Table 2 shows, Scenario 4 would have a 1.7-fold CCA renewable capacity investment
compared to Scenario 3, with almost 5-fold local project investment ($3.2 billion of county-sited
projects versus $0.67 billion).
Table 2. Initial Comparison of Proposed CCA Scenarios
2017 to
2030
Million$
nominal Million $ nominal DEMAND
Scenario Bill
Savings*
CCA Renewable
Investment CCA Renewable O&M
PG&E
Offset
Renew.
O&M
Alameda Rest of
CA
PG&E
offset RE
invest.
Rest ofCA
Alameda Rest of
CA Alameda
1 $1,574 $623 $1,676 -$1,946 $47 $133 -$153
2 $1,513 $623 $2,217 -$2,446 $47 $190 -$206
3 $522 $674 $2,514 -$2,785 $51 $200 -$219
4 $521 $3,222 $2,217 -3,325 $252 $190 -$278
*Bill savings are net of PCIA and customer out-of-pocket for renewable and energy
efficient improvements.
As can be seen from Table 3, the initial local investment that would result from building and
operating additional renewable projects in Alameda County between the years 2017 to 2030
represents a very small portion of the County’s total expected economic activity, 1 even assuming
all of the project costs are directed locally (usually 56% of the project costs would be funneled
outside the county due to procurement of equipment from outside the county). By contrast bill
savings for Scenarios 1 and 2 provide over three fold the benefits of initial local investment.
These bill savings indirectly stimulate the economy and ultimately create jobs.
1 Forecast to be $3,500 billion (nominal). Source REMI Policy Insight model, Alameda County forecast.
7
Table 3
2017 to 2030
CCA
Scenario
Local Capture on RE
investments (billion$)
As % of County’s
Total RE
investment
As % of County’s
Expected Economic
Activity
Net Bill
Savings
(billion$)
1 $0.42 44% 0.01% $1.57
2 $0.42 44% 0.01% $1.51
3 $0.45 45% 0.01% $0.52
4 $1.86 49% 0.04% $0.52
Table 4 shows high-level results expressed as average annual job changes for the four CCA
scenarios. While Scenarios 1 and 2 create nearly identical direct jobs (due to comparable
investment in local renewable projects), scenario 1 creates far more TOTAL jobs. This is due to
the higher bill savings under scenario 1. Scenario 3 creates a few more direct jobs, but far fewer
total jobs, due to decreased bill savings as compared to Scenario 3. The average annual total job
impact when compared to Scenario 3 increases by a 2.2-fold factor as a result of CCA customers
facing the same level of net rate savings despite the amplified level of renewable investment
demand associated with the CCA, particularly for local projects.
Table 4: Average Annual Jobs created in Alameda County by the CCA –
Direct and Total Impacts
2017 – to – 2030 County Impacts
CCA
Scenario
Local Capture on RE
investments
(billion$)
Bill Savings
(billion$)
Average
Annual
DIRECT Jobs
Average
Annual
TOTAL Jobs
1 $0.42 $1.57 165 1322
2 $0.42 $1.51 166 1286
3 $0.45 $0.52 174 731
4 $1.84 $0.52 579 1617
Job impacts from building and operating renewable capacity investments in the county account
for near 70 percent of annual job creation (compared to the 20 percent in Scenario 1 which had
the smallest amount of CCA renewable investments both for the county and elsewhere in the
state. It did however have the greatest rate savings to CCA customers). The peak year of impact
remains 2023 with the county adding approximately 2,430 jobs.
8
Figure 5. County's annual Total Job Impact by source (thousands)
Table 5 addresses the Scenario 4 job impacts occurring (as average annual for 2017 through
2030 and for the 2023 peak year) in the Construction sector related to both the direct and total
impact stages, juxtaposed against results for the initial scenarios. It also provides an estimate of
Construction sector job changes on “covered” work contracts, using the same approach as done
for the three initial scenarios.
Table 5: Scenario 4 Job Impacts
CCA
Scenario
Avg. Annual
Direct Jobs-
all sectors
Avg. Annual
Direct Jobs-
Construction
sector
...that are
associated
with CBA
Peak Year
Direct Jobs-
Construction
sector
...that are
associated
with CBA
1 165 80 16 136 27
2 166 81 16 137 27
3 174 86 17 154 31
4 574 318 64 359 72
CCA
Scenario
Avg. Annual
Total Jobs-
all sectors
Avg. Annual
Total Jobs-
Construction
sector
...that are
associated
with CBA
Peak Year
Total Jobs-
Construction
sector
...that are
associated
with CBA
1 1343 235 47 440 88
2 1308 231 46 432 86
3 752 160 32 326 65
4 1617 455 91 634 127
-0.5
0
0.5
1
1.5
2
2.5
3
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
scen 4 Rate savings scen 4 all other CCA fx
9