HomeMy WebLinkAboutORD 461 2018 0207 ORDINANCE NO. 461
AN ORDINANCE OF THE CITY OF MOORPARK,
CALIFORNIA, AUTHORIZING THE IMPLEMENTATION OF
A COMMUNITY CHOICE AGGREGATION PROGRAM
AND APPROVING THE JOINT POWERS AGREEMENT
FOR LOS ANGELES COMMUNITY CHOICE ENERGY
AUTHORITY
WHEREAS, the City Council has been actively investigating options to provide
electric services to constituents within its service area with the intent of achieving
greater local involvement over the provisions of electric services and promoting
competitive and renewable energy; and
WHEREAS, on September 24, 2002, the Governor signed into law Assembly Bill
117 (Stat. 2002, Ch. 838; see California Public Utilities Code section 366.2; hereinafter
referred to as the "Act"), which authorizes any California city or county, whose
governing body so elects, to combine the electricity load of its residents and businesses
in a community-wide electricity aggregation program known as Community Choice
Aggregation; and
WHEREAS, the Act expressly authorizes participation in a Community Choice
Aggregation (CCA) program through a joint powers agency, and to this end the County
of Los Angeles (County) has been participating since 2015 in the evaluation of a CCA
program for the County and the cities and towns within it; and
WHEREAS, through Docket No. R.03-10-003, the California Public Utilities
Commission has issued various decisions and rulings addressing the implementation of
CCA programs, including the recent issuance of a procedure by which the California
Public Utilities Commission will review "Implementation Plans," which are required for
submittal under the Act as the means of describing the CCA program and assuring
compliance with various elements contained in the Act; and
WHEREAS, representatives from the City along with representatives from the
County and participating cities within the County, have developed the Los Angeles
Community Choice Energy Authority Joint Powers Agreement ("Joint Powers
Agreement") (attached hereto as Exhibit A) in order to accomplish the following:
• To form a Joint Powers Authority known as "Los Angeles Community Choice
Energy Authority"; and
• To specify the terms and conditions by which participants may participate as a
group in energy programs, including but not limited to the preliminary
implementation of a CCA program; and
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WHEREAS, representatives from the City along with the County and participating
cities within the County have developed a Business Plan (attached hereto as Exhibit B)
that describes the formation of Los Angeles Community Choice Energy (LACCE)
Authority and the CCA program to be implemented by and through the LACCE
Authority; and
WHEREAS, a final Implementation Plan will be submitted for review and
adoption by the LACCE Authority's Board of Directors; and
WHEREAS, as described in the Business Plan, Community Choice Aggregation
by and through the LACCE Authority appears to provide a reasonable opportunity to
accomplish all of the following:
• To provide greater levels of local involvement in and collaboration on energy
decisions.
• To increase significantly the amount of renewable energy available to LACCE
Authority energy customers,
• To provide initial price stability, long-term electricity cost savings and other
benefits for the community, and
• To reduce greenhouse gases that are emitted by creating electricity for the
community; and
WHEREAS, the Act requires CCA program participants to individually adopt an
ordinance ("CCA Ordinance") electing to implement a CCA program within its
jurisdiction by and through its participation in the LACCE Authority; and
WHEREAS, based on the feasibility studies and Business Plan, it is in the
public's interest and welfare to establish a CCA program within the City of Moorpark;
and
WHEREAS, the Joint Powers Agreement expressly allows the City to withdraw
its membership in the LACCE Authority (and its participation in the CCA program) by
providing no less than 180 days advance written notice to the LACCE Authority.
NOW, THEREFORE, THE CITY COUNCIL OF THE CITY OF MOORPARK
DOES ORDAIN AS FOLLOWS:
SECTION 1. That the recitals set forth above are true and correct and are
incorporated as though fully set forth herein.
Ordinance No. 461
Page 3
SECTION 2. Based upon the findings and declarations set forth in this
ordinance, and in order to provide businesses and residents within the jurisdictional
boundaries of the City with a choice of power providers and with the benefits described
in the recitals above, the City Council hereby: (a) elects to implement a CCA program
within the City by participating in the Community Choice Aggregation Program of the
LACCE JPA, as described in its Joint Powers Agreement; and (b) approves the
execution of the LACCE JPA Joint Powers Agreement.
SECTION 3. If any section, subsection, sentence, clause, phrase, part or portion of
this ordinance is for any reason held to be invalid or unconstitutional by any court of
competent jurisdiction, such decision shall not affect the validity of the remaining portions
of this ordinance. The City Council declares that it would have adopted this ordinance and
each section, subsection, sentence, clause, phrase, part or portion thereof, irrespective of
the fact that any one or more section, subsections, sentences, clauses, phrases, parts or
portions be declared invalid or unconstitutional.
SECTION 4. This ordinance shall become effective thirty (30) days after its
passage and adoption.
SECTION 5. The City Clerk shall certify to the passage and adoption of this
ordinance; shall enter the same in the book of original ordinances of said City; shall make
a written record of the passage and adoption thereof in the minutes of the proceedings of
the City Council at which the same is passed and adopted; and shall publish notice of
adoption in the manner required by law.
PASSED AND ADOPTED this 7th day of February, 2018
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Ja ce S. Parvin, Mayor
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ATTEST:
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Maureen Benson, City Clerk � g,k
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Attachments: Exhibit A - Joint Powers Agreement
Exhibit B — LACCE Business Plan
Ordinance No. 461
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EXHIBIT A
LOS ANGELES COMMUNITY CHOICE ENERGY AUTHORITY
JOINT POWERS AGREEMENT
This Joint Powers Agreement (the"Agreement"), effective as of June 27, 2017, 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
public agencies set forth in Exhibit A.
RECITALS
1. The Parties are public agencies sharing various powers under California laws, including
but not limited to the power to purchase supply, and aggregate electricity for themselves and
their inhabitants.
2. In 2006,the State Legislature adopted AB 32,the Global Warming Solutions Act,which
mandates a reduction in greenhouse gas emissions in 2020 to 1990 levels. The California Air Resources
Board is promulgating regulations to implement AB 32 which will require local government to develop
programs to reduce greenhouse emissions.
3. The purposes for the Initial Participants (as such term is defined in Section 2.3 below) entering
into this Agreement include addressing climate change by reducing energy related greenhouse gas
emissions and securing energy supply and price stability; energy efficiencies and local economic
benefits, 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 solar and wind energy production.
4. The Parties desire to establish a separate public agency, known as the Los Angeles Community
Choice 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) Develop an electric supply portfolio with overall lower greenhouse gas intensity and
lower greenhouse gas (GHG) emissions than Southern California Edison ("SCE"), and one that supports
the achievement of the parties'greenhouse gas reduction goals and the comparable goals of all
participating jurisdictions;
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(b) Establish an energy portfolio that encourages the use and development of cost-effective
local renewable and distributed energy resources and that discourages the use unbundled renewable
energy credits;
(c) Promote an energy portfolio that incorporates energy efficiency and demand response
programs and pursues ambitious energy consumption reduction goals;
(d) Provide electricity rates that are lower or at worst competitive with those offered by
SCE for similar products;
(e) 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;
(f) Achieve quantifiable economic benefits to the region;
(g) Recognize the value of current workers in existing jobs that support the energy
infrastructure of Los Angeles County and Southern California (e.g. union and prevailing wage jobs, local
workforce development, apprenticeship programs,and local hire). The Authority, as a leader in the shift
to 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) Support a stable, skilled workforce through such mechanisms as project labor
agreements,collective bargaining agreements, or community benefit agreements, or other workforce
programs that are designed to avoid work stoppages, ensure quality, and benefit local residents by
delivering cost-effective clean energy programs and projects(e.g. new energy programs and increased
local energy investments);
(i) Promote supplier and workforce diversity, including returning veterans and those from
disadvantaged and under-represented communities,to better reflect the diversity of the region;
(j) Promote personal and community ownership of renewable resources, spurring
equitable economic development and increased resilience,especially in low income communities;
(k) Provide and manage its energy portfolio and products in a manner that provides cost
savings to customers and promotes public health in areas impacted by energy production;
(I) Ensure that low-income households and communities are provided with affordable and
flexible energy options, including the provision of energy discounted rates to eligible low-income
households;
(m) Recognize and address the importance of healthy communities, including those
disproportionately affected by air pollution and climate change;
(n) Use program revenues to provide energy-related programs and services; and
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(o) Create an administering Authority that is financially sustainable, responsive to regional
priorities,well-managed, and a leader in fair and equitable treatment of employees.
1. DEFINITIONS
1.1 "AB 117" means Assembly Bill 117 (Stat. 2002, Ch. 838, codified at Public
Utilities Code Section 366.2), which created Community Choice Aggregation.
1.2 "Act" means the Joint Exercise of Powers Act of the State of California
(Chapter 5, Division 7, Title 1 of the Government Code commencing with
Section 6500).
1.3 "Agreement" means this Joint Powers Agreement.
1.4 "Authority" means Los Angeles Community Choice Energy Authority.
1.5 "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 Policies and Procedures, the
annual budget, and plans and policies.
1.6 "Board" means the Board of Directors of the Authority.
1.7 "Community Choice Aggregation" or "CCA" means an electric service option
available to cities, counties, and other public agencies pursuant to Public Utilities
Code Section 366.2.
1.8 "CCA Program" means the Authority's program relating to CCA that is
principally described in Section 2.4 (Purpose) of this Agreement.
1.9 "Days" shall mean calendar days unless otherwise specified by this Agreement.
1.10 "Director" means a member of the Board representing a Party, including up to two
alternate Directors appointed in accordance with Sections 4.1 (Board of Directors)
and 4.2 (Appointment and Removal of Directors) of this Agreement.
1.11 "Effective Date" means the date on which the Agreement shall become effective
and the Authority shall exist as a separate public agency, as further described in
Section 2.1 (Effective Date and Term) of this Agreement.
1.12 "Initial Costs" means all costs incurred by the Authority relating to the
establishment and initial operation of the Authority, such as the hiring of the
executive, technical, 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
the Initial Costs.
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1.13 "Initial Participants" means, for purpose of this Agreement, the County of
Los Angeles, and the cities of , and any
other Parties joining in accordance with Section 2.3 (Initial Participants) of this
Agreement.
1.14 "Operating Policies and Procedures" means the rules, regulations, policies, bylaws
and procedures governing the operation of the Authority.
1.15 "Parties" means, collectively, the signatories to this Agreement that have satisfied
the conditions in Sections 2.3 (Initial Participants) or 2.5 (Addition of Parties) of
this Agreement, such that they are considered members of the Authority.
1.16 "Party" means, singularly, a signatory to this Agreement that has satisfied the
conditions in Sections 2.3 (Initial Participants) or 2.5 (Addition of Parties) of this
Agreement, such that it is considered a member of the Authority.
1.17 "Public Agency" as defined in the Act includes,but is not limited to, the federal
government or any federal department or agency, this state, another state or any
state department or agency, a county, a county board of education, county
superintendent of schools, city, public corporation, public district, regional
transportation commission of this state or another state, a federally recognized
Indian tribe, or any joint powers authority formed pursuant to the Act.
2. FORMATION OF LOS ANGELES COMMUNITY CHOICE ENERGY
AUTHORITY
2.1 Effective Date and Term. This Agreement shall become effective and the
Authority shall exist as a separate public agency on the date this Agreement is
executed by the County of Los Angeles and at least one other public agency 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 the Agreement is terminated in accordance with Section 8.3
(Mutual Termination) of this Agreement, subject to the rights of the Parties to
withdraw from the Authority.
2.2 Formation of the Authority. Under the Act, the Parties hereby create a separate
joint exercise of power agency which is named Los Angeles Community Choice
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 body of a Party agrees in writing to assume any of
the debts, liabilities or obligations of the Authority. The jurisdiction of the
Authority shall be all territory within the geographic boundaries of the Parties;
however the Authority may, as authorized under applicable law, undertake any
Ordinance No. 461
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action outside such geographic boundaries as is necessary and incidental to the
accomplishment of its purpose.
2.3 Initial Participants. In addition to Parties executing this Agreement on or prior
to the Effective Date, any incorporated municipality, county, or other eligible
public agency may become a Party and recognized as an Initial Participant
provided during the first 180 days after the Effective Date it executes this
Agreement and delivers 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. All Initial Participants to this Agreement shall be required to
commence electric service as soon as practicable, as determined by the Board.
2.4 Purpose. The purpose and objectives of this Agreement are to establish the
Authority, to provide for its governance and administration, and to define the
rights and obligations of the Parties. This Agreement authorizes the Authority to
provide a means by which the Parties can more effectively develop and
implement sustainable energy initiatives that reduce energy demand, increase
energy efficiency, and advance the use of clean, efficient, and renewable
resources in the region for the benefit of the Parties and their constituents,
including,but not limited to, establishing and operating a Community Choice
Aggregation program.
2.5 Addition of Parties. After 180 days from the Effective Date any incorporated
municipality, county, or other public agency may become a Party to this
Agreement if all of the following conditions are met:
2.5.1 The adoption of a resolution of the Board admitting the public agency to
the Authority;
2.5.2 The adoption by an affirmative vote of the Board satisfying the
requirements described in Section 4.10 (Board Voting) of this Agreement,
of a resolution authorizing membership into the Authority and establishing
its pro rata share of organizational, planning and other pre-existing
expenditures, and describing additional conditions, if any, associated with
membership;
2.5.3 The adoption by the public agency of an ordinance required by Public
Utilities Code Section 366.2(c)(12) and approval and execution of this
Agreement and other necessary program agreements by the public agency;
2.5.4 Payment of the membership payment, if any; and
2.5.5 Satisfaction of any reasonable conditions established by the Board.
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Pursuant to this Section 2.5 (Addition of Parties), all parties shall be required to
commence electric service as soon as is practicable, as determined by the Board,
as a condition to becoming a Party to this Agreement.
2.6 Continuing Participation. The Parties acknowledge that membership in the
Authority may change by the addition, withdrawal and/or termination of Parties.
The Parties agree to participate with such other Parties as may later be added, as
described in Section 2.5 (Addition of Parties) of this Agreement. 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.
3. POWERS
3.1 General Powers. The Authority shall have the powers common to the Parties
and which are necessary or convenient to the accomplishment of the purposes of
this Agreement, subject to the restrictions set forth in Section 3.4 (Limitation on
Powers) of this Agreement. As provided in the Act, the Authority shall be a
public agency separate and apart from the Parties.
3.2 Specific 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:
3.2.1 make and enter into contracts;
3.2.2 employ agents and employees, including but not limited to an Executive
Director;
3.2.3 acquire, contract,manage, maintain, and operate any buildings, works or
improvements;
3.2.4 acquire property by eminent domain, or otherwise, except as limited under
Section 6508 of the Act, and to hold or dispose of any property;
3.2.5 lease any property;
3.2.6 sue and be sued in its own name;
3.2.7 incur debts, liabilities, and obligations, including but not limited to loans
from private lending sources pursuant to its temporary borrowing powers
authorized by law pursuant to Government Code Section 53850 et seq. and
authority under the Act;
3.2.8 issue revenue bonds and other forms of indebtedness;
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3.2.9 apply for, accept, and receive all licenses,permits, grants, loans or other
aids from any federal, state or local public agency;
3.2.10 form independent corporations or entities, if necessary to carry out energy
supply and energy conservation programs at the lowest possible cost or to
take advantage of legislative or regulatory changes;
3.2.11 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;
3.2.12 adopt rules, regulations, policies,bylaws and procedures governing the
operation of the Authority("Operating Policies and Procedures"); and
3.2.13 make and enter into service agreements relating to the provision of
services necessary to plan, implement, operate and administer the CCA
Program and other energy programs, including the acquisition of electric
power supply and the provision of retail and regulatory support services.
3.3 Additional Powers to be Exercised. In addition to those powers common to
each of the Parties, the Authority shall have those powers that may be conferred
upon it as a matter of law and by subsequently enacted legislation.
3.4 Limitation on Powers. As required by Section 6509 of the Act, the powers of
the Authority are subject to the restrictions upon the manner of exercising power
possessed by the County of Los Angeles.
3.5 Obligations of the Authority. The debts, liabilities, and obligations of the
Authority shall not be the debts, liabilities, and obligations of the Parties unless
the governing body of a Party agrees in writing to assume any of the debts,
liabilities, and obligations of the Authority. In addition, pursuant to the Act, no
Director shall be personally liable on the bonds or subject to any personal liability
or accountability by reason of the issuance of bonds.
3.6 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. The Board shall adopt a Conflict of
Interest Code pursuant to Government Code Section 87300. The Board may
adopt additional conflict of interest regulations in the Operating Policies and
Procedures.
4. GOVERNANCE
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
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accordance with Section 4.2 (Appointment and Removal of Directors) of this
Agreement. The Board, in consultation with the Executive Director, may
determine at any time to consider options to reduce the size of the Board if it
determines that the efficient functioning and operation of the Board would be
improved by having a smaller number of Directors. Any such change to the size
of the Board would require amendment of this Joint Powers Agreement in
accordance with Section 4.11 (Special Voting).
4.2 Appointment and Removal of Directors. The Directors shall be appointed and
may be removed as follows:
4.2.1 The governing body of each Party shall appoint and designate in writing
one regular Director who shall be authorized to act for and on behalf of the
Party on matters within the powers of the Authority. The governing body
of each Party shall appoint and designate in writing up to two alternate
Directors who may vote on matters when the regular Director is absent
from a Board meeting. The person appointed and designated as the
regular Director shall be an elected or appointed member of the governing
body of the Party. The persons appointed and designated as the alternate
Directors may be an elected or appointed member of the governing body
of the Party, an appointed member of an advisory body of the Party, a staff
member of the Party or a member of the public who meets the criteria
below. All Directors and alternates shall be subject to the Board's adopted
Conflict of Interest Code.
(a) Any alternate Director that is a member of the public must have
demonstrated knowledge in energy-related matters through
significant experience in either: 1) an electric utility or company,
agency, or nonprofit providing services to a utility, 2) a regulatory
agency or local government body overseeing an electric utility or a
company, agency, or nonprofit providing services to such an
agency, 3) an academic or nonprofit organization engaged in
research and/or advocacy related to the electric sector.
4.2.2 The Operating Policies and Procedures, to be developed and approved by
the Board in accordance with Section 3.2.12 (Specific Powers), shall
specify the reasons for and process associated with the removal of an
individual Director for cause. Notwithstanding the foregoing, no Party
shall be deprived of its right to seat a Director on the Board and any such
Party for which its Director and/or alternate Directors have been removed
may appoint a replacement.
4.3 Terms of Office. Each regular and alternate Director shall serve at the pleasure
of the governing body of the Party that the Director represents, and may be
removed as Director by such governing body at any time. If at any time a
vacancy occurs on the Board, the affected Party shall appoint to fill the position of
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the previous Director within 90 days of the date that such position becomes
vacant.
4.4 Purpose of Board. The general purpose of the Board is to:
4.4.1 Provide structure for administrative and fiscal oversight;
4.4.2 Retain an Executive Director to oversee day-to-day operations;
4.4.3 Retain legal counsel;
4.4.4 Identify and pursue funding sources;
4.4.5 Set policy;
4.4.6 Maximize the utilization of available resources; and
4.4.7 Oversee all Committee activities.
4.5 Specific Responsibilities of the Board. The specific responsibilities of the
Board shall be as follows:
4.5.1 Identify Party needs and requirements;
4.5.2 Formulate and adopt the budget prior to the commencement of the fiscal
year;
4.5.3 Develop and implement a financing and/or funding plan for ongoing
Authority operations;
4.5.4 Retain necessary and sufficient staff and adopt personnel and
compensation policies, rules and regulations;
4.5.5 Adopt rules for procuring supplies, equipment, and services;
4.5.6 Adopt rules for the disposal of surplus property;
4.5.7 Establish standing and ad hoc committees as necessary to ensure that the
interests and concerns of each Party are represented and to ensure
operational, technical, and financial issues are thoroughly researched and
analyzed;
4.5.8 The setting of retail rates for power sold by the Authority and the setting
of charges for any other category of retail service provided by the
Authority;
4.5.9 Termination of the CCA Program;
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4.5.10 Address any concerns of consumers and customers;
4.5.11 Conduct and oversee Authority audits at intervals not to exceed three
years;
4.5.12 Arrange for an annual independent fiscal audit;
4.5.13 Adopt such bylaws, rules and regulations as are necessary or desirable for
the purposes hereof; provided that nothing in the bylaws, rules and
regulations shall be inconsistent with this Agreement;
4.5.14 Exercise the Specific Powers identified in Sections 3.2 and 4.6 except as
the Board may elect to delegate to the Executive Director; and
4.5.15 Discharge other duties as appropriate or required by statute.
4.6 Startup Responsibilities. The Authority shall have the duty to do the following
within one year of the Effective Date of the Agreement:
4.6.1 To adopt an implementation plan prepared by the County of Los Angeles,
pursuant to Public Utilities Code Section 366.2(c)(3), for electrical load
aggregation;
4.6.2 To prepare a statement of intent,pursuant to Public Utilities Code
Section 366.2(c)(4), for electrical load aggregation;
4.6.3 To encourage other qualified public agencies to participate in the
Authority;
4.6.4 To obtain financing and/or funding as is necessary or desirable;
4.6.5 To evaluate the need for, acquire, and maintain insurance.
4.7 Meetings and Special Meetings of the Board. The Board shall hold at least one
regular meetings per year but the Board may provide for the holding of regular
meetings at more frequent intervals. The date, hour and place of each regular
meeting shall be fixed by resolution or ordinance of the Board. Regular meetings
may be adjourned to another meeting time. Special meetings of the Board may be
called in accordance with the provisions of Government Code Section 54956.
Directors may participate in meetings telephonically, with full voting rights, only
to the extent permitted by law.
4.8 Brown Act Applicable. All meetings of the Board shall be conducted in
accordance with the provisions of the Ralph M. Brown Act (Government Code
Section 54950, et seq.).
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4.9 Quorum; Approvals. A majority of the Directors shall constitute a quorum,
except that less than a quorum may adjourn from time to time in accordance with
law. The affirmative votes of a majority of the Directors who are present at the
subject meeting shall be required to take any action by the Board.
4.10 Board Voting.
4.10.1 Percentage Vote. Each Director shall have one vote. Action of the Board
on all matters shall require an affirmative vote of a majority of all
Directors who are present at the subject meeting, except when a
supermajority vote is expressly required by this Agreement. When a
supermajority vote is required under Section 4.11 (Special Voting), action
of the Board shall require an affirmative vote of the specified
supermajority of all Directors who are present at the subject meeting. All
votes taken pursuant to this Section 4.10.1 shall be referred to as a
percentage vote. Notwithstanding the foregoing, in the event of a tie in a
percentage vote, the Board can break the tie and act upon an affirmative
voting shares vote as described in section 4.10.2 (Voting Shares Vote).
4.10.2 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. In such event, the corresponding voting
shares, as described in section 4.10.3, of all Directors voting in order to
take an action shall exceed 50%, or such other higher voting shares
percentage expressly required by this Agreement or the Operating Policies
and Procedures of all Directors who are present at the subject meeting.
All votes taken pursuant to this Section 4.10.2 shall be referred to as a
voting shares vote. In the event that any one Director has a voting share
that equals or exceeds that which is necessary to disapprove the matter
being voted on by the Board, at least one other Director shall be required
to vote in the negative in order to disapprove such matter. When a voting
shares vote is held, action by the Board requires both an affirmative
percentage vote and an affirmative voting shares vote.
4.10.3 Voting Shares Formula. When a voting shares vote is requested by
three or more Directors, voting shares of the Directors shall be 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.
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4.11 Special Voting.
4.11.1 Except as provided below, matters that require Special Voting as
described in this Section shall require 72 hours prior notice to any Brown
Act meeting or special meeting. Two-thirds vote(or such greater vote as
required by state law) of the appointed Directors shall be required to take
any action on the following:
(a) Change the designation of Treasurer or Auditor of the Authority;
(b) Issue bonds or other forms of debt;
(c) Exercise the power of eminent domain, subject to prior approval
by the passage of an authorizing ordinance or other legally
sufficient action by the affected Party; and
(d) Amend this Agreement or adopt or amend the bylaws of the
Authority. At least 30 days advance notice shall be provided for
such actions. The Authority shall also provide prompt written
notice to all Parties of the action taken and enclose the adopted or
modified documents.
5. INTERNAL ORGANIZATION
5.1 Chair and Vice Chair. For each fiscal year, the Board shall elect a Chair and
Vice Chair from among the Directors. The term of office of the Chair and Vice
Chair shall continue for one year, but there shall be no limit on the number of
terms held by either the Chair or Vice Chair. The Chair shall be the presiding
officer of all Board meetings, and the Vice Chair shall serve in the absence of the
Chair. The Chair shall sign all contracts on behalf of the Authority, and shall
perform such other duties as may be imposed by the Board. In the absence of the
Chair, the Vice-Chair shall sign contracts and perform all of the Chair's duties.
The office of the Chair or Vice Chair shall be declared vacant and a new selection
shall be made if: (a) the person serving dies, resigns, or the Party that the person
represents removes the person as its representative on the Board, or (b) the Party
that he or she represents withdraws from the Authority pursuant to the provisions
of this Agreement. Upon a vacancy, the position shall be filled at the next
regular meeting of the Board held after such vacancy occurs or as soon as
practicable thereafter. Succeeding officers shall perform the duties normal to said
offices.
5.2 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 office records of the Authority.
Ordinance No. 461
Page 16
5.3 Treasurer. The Board shall appoint a qualified person to act as the Treasurer,
who need not be a member of the Board. Unless otherwise exempted from such
requirement, the Authority shall cause an independent audit to be made by a
certified public accountant, or public accountant, in compliance with Section 6506
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 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.
5.4 Auditor. The Board shall appoint a qualified person to act as the Auditor, who
shall not be a member of the Board. The Board may require the 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.
5.5 Executive Director. The Board shall appoint an Executive Director for the
Authority, who shall be responsible for the day-to-day operation and management
of the Authority and the CCA Program. The Executive Director may exercise all
powers of the Authority, except those powers specifically reserved to the Board
including but not limited to those set forth in Section 4.5 (Specific
Responsibilities of the Board) of this Agreement or the Operating Policies and
Procedures, or those powers which by law must be exercised by the Board. The
Executive Director may enter into and execute any Energy Contract, in
accordance with criteria and policies established by the Board.
5.6 Bonding of Persons Having Access to Property. Pursuant to the Act, the Board
shall designate the public officer or officers or person or persons who have charge
of, handle, or have access to any property of the Authority exceeding a value as
established by the Board, and shall require such public officer or officers or
person or persons to file an official bond in an amount to be fixed by the Board.
5.7 Other Employees/Agents. The Board shall have the power by resolution to hire
employees or appoint or retain such other agents, including officers, loan-out
employees, or independent contractors, as may be necessary or desirable to carry-
out the purpose of this Agreement.
5.8 Privileges and Immunities from Liability. All of the privileges and immunities
from liability, exemption from laws, ordinances and rules, all pension, relief,
disability, workers' compensation and other benefits which apply to the activities
of officers, agents or employees of a public agency when performing their
respective functions shall apply to the officers, agents or employees of the
Ordinance No. 461
Page 17
Authority to the same degree and extent while engaged in the performance of any
of the functions and other duties of such officers, agents or employees under this
Agreement. None of the officers, agents or employees directly employed by the
Board shall be deemed,by reason of their employment by the Authority to be
employed by the Parties or by reason of their employment by the Authority, to be
subject to any of the requirements of the Parties.
5.9 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 outs 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.
5.9.1 The Board shall establish the following Advisory Committees:
(a) Executive Committee. The Board shall establish an executive
committee consisting of a smaller number of Directors. The Board
may delegate to the Executive Committee's such authority as the
Board might otherwise exercise, except that the Board may not
delegate authority regarding certain essential functions, including
but not limited to, approving the fiscal year budget or hiring or
firing the Executive Director, and other functions as provided in
the Operating Policies and Procedures. The Board may not
delegate to the Executive Committee or any other committee its
authority under Section 3.2.12 to adopt and amend the Operating
Policies and Procedures.
(b) Finance Committee. The Board shall establish a finance
committee consisting of a smaller number of Directors. The
primary purpose of the Finance Committee is to review and
recommend to the Board:
(1) A funding plan;
(2) A fiscal year budget;
(3) Financial policies and procedures to ensure equitable
contributions by Parties;
(4) Such other responsibilities as provided in the Operating
Policies and Procedures, including but not limited to
policies, rules and regulations governing investment of
surplus funds, and selection and designation of financial
institutions for deposit of Authority funds.
Ordinance No. 461
Page 18
(c) Community Advisory Committee. The Board shall establish a
community advisory committee comprised of members of the
public representing key stakeholder communities. The primary
purpose of the Community Advisory Committee shall be to
provide a venue for ongoing citizen support and engagement in the
operations of the Authority.
(d) Meetings of the Advisory Committees. All meetings of the
Advisory Committees shall be held in accordance with the Ralph
M. Brown Act. For the purposes of convening meetings and
conducting business, unless otherwise provided in the bylaws, a
majority of the members of the Advisory Committee shall
constitute a quorum for the transaction of business, except that less
than a quorum or the secretary of each Advisory Committee may
adjourn meetings from time-to-time. As soon as practicable,but no
later than the time of posting, the Secretary of the Advisory
Committee shall provide notice and the agenda to each Party,
Director and Alternate Directors.
(e) Officers of Advisory Committees. Unless otherwise determined
by the Board, each Advisory Committee shall choose its officers,
comprised of a Chairperson, a Vice-Chairperson and a Secretary.
6. IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS
6.1 Preliminary Implementation of the CCA Program.
6.1.1 Enabling Ordinance. In addition 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.
6.1.2 Implementation Plan. The Authority shall cause to be prepared and
secure Board approval of 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. .
6.1.3 Termination of CCA Program. Nothing contained in this Section 6 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.
6.2 Authority Documents. The Parties acknowledge and agree that the affairs of the
Authority will be implemented through various documents duly adopted by the
Ordinance No. 461
Page 19
Board through Board resolution or minute action, including but not necessarily
limited to the Operating Policies and Procedures, 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 Section 8 (Withdrawal and
Termination) of this Agreement.
7. FINANCIAL PROVISIONS
7.1 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.
7.2 Depository.
7.2.1 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.
7.2.2 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 and duplication by the Parties at all
reasonable times. The Board shall contract with a certified public
accountant or public accountant to make an annual audit of the accounts
and records of the Authority, which shall be conducted in accordance with
the requirements of Section 6506 of the Act.
7.2.3 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 Policies and Procedures. 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.
7.3 Budget and Recovery Costs.
7.3.1 Budget. The initial budget shall be approved by the Board. The Board
may revise the budget from time to time 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 Policies and Procedures.
7.3.2 Funding of Initial Costs. Subject to the approval of the Board of
Supervisors, the County of Los Angeles has agreed to provide up to $10
million for funding Initial Costs in establishing the Authority and
Ordinance No. 461
Page 20
implementing the CCA Program. In the event that the CCA Program
becomes operational, the County of Los Angeles shall be reimbursed for
the Initial Costs. The County and the Authority will execute an agreement
specifying the terms and conditions of the Initial Costs provided by the
County, including but not limited to: (a) Repayment of this amount,
which shall be first priority in relation to all other indebtedness of the
Authority; and(b) authorization for the County Auditor-Controller to
conduct an audit of the Authority's books and records (including personnel
records, as necessary) and/or investigation, following reasonable advance
notice from the County, to ensure compliance with the terms and
conditions of the agreement. 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 they have paid from the
Authority or any other Party.
7.3.3 Program Costs. The Parties desire that, to the extent reasonably
practicable, all costs incurred by the Authority that are directly or
indirectly attributable to the provision of electric services under the CCA
Program, including the establishment and maintenance of various reserve
and performance funds, shall be recovered through charges to CCA
customers receiving such electric services.
7.3.4 General Costs. Costs that are not directly or indirectly attributable to the
provision of electric services under the CCA Program, as determined by
the Board, shall be defined as general costs. General costs shall be shared
among the Parties on such bases as the Board shall determine pursuant to
the Authority documents.
7.4 Contributions. Parties are not required under this Agreement to make any
financial contributions. Consumers may subscribe as customers of the Authority
pursuant to the Act and outside of this Agreement and through their on-bill
selections.
7.4.1 A Party may, in the appropriate circumstance, and when agreed-to:
(a) Make contributions from its treasury for the purposes set forth in
this Agreement;
(b) Make payments of public funds to defray the cost of the purposes
of the Agreement and Authority;
(c) Make advances of public funds for such purposes, such advances
to be repaid as provided by written agreement; or
Ordinance No. 461
Page 21
(d) Use its personnel, equipment or property in lieu of other
contributions or advances.
(e) No Party shall be required to adopt any tax, assessment, fee or
charge under any circumstances.
7.5 Accounts and Reports. The Treasurer shall establish and maintain such funds
and accounts as may be required by good accounting practice or by any provision
of any trust agreement entered into with respect to the proceeds of any bonds
issued by the Authority. The books and records of the Authority in the hands of
the Treasurer shall be open to inspection and duplication at all reasonable times
by duly appointed representatives of the Parties. The Treasurer, within 180 days
after the close of each fiscal year, shall give a complete written report of all
financial activities for such fiscal year to the Parties.
7.6 Funds. The Treasurer shall receive, have custody of and/or disburse Authority
funds in accordance with the laws applicable to public agencies and generally
accepted accounting practices, and shall make the disbursements required by this
Agreement in order to carry out any of the purposes of this Agreement.
8. WITHDRAWAL AND TERMINATION
8.1 Withdrawal
8.1.1 Withdrawal by Parties. Any 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.
8.1.2 Amendment. Notwithstanding Section 8.1.1 (Withdrawal by Parties) of
this Agreement, a Party may withdraw its membership in the Authority
upon approval and execution of an amendment to this Agreement provided
that the requirements of this Section 8.1.2 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.
8.1.3 Continuing Liability; Further Assurances. A Party that withdraws its
membership in the Authority may be subject to certain continuing
liabilities, as described in Section 8.4 (Continuing Liability; Refund) of
this Agreement, including,but not limited to, Power Purchase
Ordinance No. 461
Page 22
Agreements. The withdrawing Party and the Authority shall execute and
deliver all further instruments and documents, and take any further action
that may be reasonably necessary, as determined by the Board, to
effectuate the orderly withdrawal of such Party from membership in the
Authority. The Operating Policies and Procedures shall prescribe the
rights if any of a withdrawn Party to continue to participate in those Board
discussions and decisions affecting customers of the CCA Program that
reside or do business within the jurisdiction of the Party.
8.2 Involuntary Termination. This Agreement may be terminated with respect to a
Party for material non-compliance with provisions of this Agreement or the
Authority Documents upon an affirmative vote of the Board in which the
minimum percentage vote and percentage voting shares, as described in
Section 4.10 (Board Voting) of this Agreement, shall be no less than 67%
excluding the vote and voting shares of the Party subject to possible termination.
Prior to any vote to terminate this Agreement with respect to a Party, written
notice of the proposed termination and the reason(s) for such termination shall be
delivered to the Party whose termination is proposed at least 30 days prior to the
regular Board meeting at which such matter shall first be discussed as an agenda
item. The written notice of proposed termination shall specify the particular
provisions of this Agreement or the Authority Documents that the Party has
allegedly violated. The Party subject to possible termination shall have the
opportunity at the next regular Board meeting to respond to any reasons and
allegations that may be cited as a basis for termination prior to a vote regarding
termination. A Party that has had its membership in the Authority terminated may
be subject to certain continuing liabilities, as described in Section 8.4 (Continuing
Liability; Refund) of this Agreement. In the event that the Authority decides to
not implement the CCA Program, the minimum percentage vote of 67% shall be
conducted in accordance with Section 4.10 (Board Voting) of this Agreement.
8.3 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 8.1 (Withdrawal) of this Agreement.
8.4 Continuing Liability; Refund. Upon a withdrawal or involuntary termination of
a Party, the Party shall remain responsible for any claims, demands, damages, or
liabilities arising from the Party's membership in the Authority through the date
of its withdrawal or involuntary termination, it being agreed that the Party shall
not be responsible for any claims, demands, damages, or liabilities arising after
the date of the Party's withdrawal or involuntary termination. In addition, such
Party also shall be responsible for any costs or obligations associated with the
Party's participation in any program in accordance with the provisions of any
agreements relating to such program provided such costs or obligations were
Ordinance No. 461
Page 23
incurred prior to the withdrawal of the Party. The Authority may withhold funds
otherwise owing to the Party or may require the Party to deposit sufficient funds
with the Authority, as reasonably determined by the Authority, to cover the
Party's liability for the costs described above. Any amount of the Party's funds
held on deposit with the Authority above that which is required to pay any
liabilities or obligations shall be returned to the Party.
8.5 Disposition of Authority Assets. Upon termination of this Agreement and
dissolution of the Authority by all Parties, and after payment of all obligations of
the Authority, the Board:
8.5.1 May sell or liquidate Authority property; and
8.5.2 Shall distribute assets to Parties in proportion to the contributions made by
the existing Parties.
Any assets provided by a Party to the Authority shall remain the asset of that
Party and shall not be subject to distribution under this section.
9. MISCELLANEOUS PROVISIONS
9.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts
to settle all disputes arising out of or in connection with this Agreement. Before
exercising any remedy provided by law, a Party or the Parties and the Authority
shall engage in nonbinding mediation or arbitration in the manner agreed upon by
the Party or Parties and the Authority. The Parties agree that each Party may
specifically enforce this section 9.1 (Dispute Resolution). In the event that
nonbinding mediation or arbitration is not initiated or does not result in the
settlement of a dispute within 60 days after the demand for mediation or
arbitration is made, any Party and the Authority may pursue any remedies
provided by law.
9.2 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.
9.3 Indemnification of Parties. The Authority shall acquire such insurance coverage
as is necessary to protect the interests of the Authority, the Parties and the public.
Ordinance No. 461
Page 24
The Authority shall defend, indemnify and hold harmless the Parties and each of
their respective governing board 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.
9.4 Notices. Any notice required or permitted to be made hereunder shall be in
writing and shall be delivered in the manner prescribed herein at the principal
place of business of each Party. The Parties may give notice by(1)personal
delivery; (2) e-mail; (3) U.S. Mail, first class postage prepaid, or a faster delivery
method; or(3)by any other method deemed appropriate by the Board.
Upon providing written notice to all Parties, any Party may change the designated
address or e-mail for receiving notice.
All written notices or correspondence sent in the described manner will be
deemed given to a party on whichever date occurs earliest: (1) the date of personal
delivery; (2) the third business day following deposit in the U.S. mail, when sent
by"first class"mail; or(3) the date of transmission, when sent by e-mail or
facsimile.
9.5 Successors. This Agreement shall be binding upon and shall inure to the benefit
of the successors of each Party.
9.6 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 9.6 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 9.6 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 the 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.
9.7 Severability. If any one or more of the terms,provisions,promises, covenants, or
conditions of this Agreement were adjudged invalid or void by a court of
competent jurisdiction, each and all of the remaining terms, provisions, promises,
covenants, and conditions of this Agreement shall not be affected thereby and
shall remain in full force and effect to the maximum extent permitted by law.
9.8 Governing Law. This Agreement is made and to be performed in the State of
California, and as such California substantive and procedural law shall apply.
Ordinance No. 461
Page 25
9.9 Headings. The section headings herein are for convenience only and are not to
be construed as modifying or governing the language of this Agreement.
9.10 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.
CITY OF MOORPARK
By:
Janice S. Parvin, Mayor
ATTEST:
By:
Maureen Benson City Clerk
Ordinance No.461
26
EXHIBIT B
EES Consulting
June 30, 2016
Mr. Howard Choy
County of Los Angeles
Energy Management Division
1100 N. Eastern Avenue
Los Angeles, CA 90063
SUBJECT: County of Los Angeles Community Choice Energy (LACCE) Business Plan
Dear Mr. Choy:
Please find attached EES Consulting, Inc.'s (EES) Community Choice Energy Business Plan (Plan)
for the County of Los Angeles (County). This Plan represents the work product of EES and Bki in
evaluating the prudency of implementing a Community Choice Energy organization for the
County.
We want to thank you and your staff for your assistance in preparing this Plan. It has been a
pleasure working with you on this project.
Please contact me directly if there are questions or if we may be of any further assistance.
Very truly yours,
ty-r6
Gary Saleba
President
Ordinance No.461
27
Contents
CONTENTS I
EXECUTIVE SUMMARY 1
BACKGROUND 1
DESCRIPTION OF LACCE 1
GOVERNANCE 2
RISKS 3
PLAN RESULTS 3
RENEWABLE ENERGY IMPACTS 4
ENERGY EFFICIENCY PROGRAMS 5
ECONOMIC DEVELOPMENT 5
GREEN HOUSE GAS IMPACTS 6
SUMMARY 7
INTRODUCTION 8
BACKGROUND 8
OBJECTIVE 8
LACCE DESCRIPTION 8
CUSTOMER PARTICIPATION SCHEDULE 9
SUMMARY OF LACCE'S PROPOSED GOVERNANCE AND OPERATIONS 10
PLAN METHODOLOGY 11
PLAN UNCERTAINTIES 12
PLAN ORGANIZATION 13
LOAD REQUIREMENTS 14
LACCE JPA MEMBERSHIP PARTICIPATION RATES 14
LACCE CUSTOMER PARTICIPATION RATES 14
HISTORICAL CONSUMPTION 15
FORECAST CONSUMPTION AND CUSTOMERS 18
RENEWABLE RESOURCE REQUIREMENT 20
RESOURCE ADEQUACY REQUIREMENTS 21
POWER SUPPLY STRATEGY AND COSTS 22
RESOURCE STRATEGY 22
RESOURCE COSTS 22
TRANSMISSION 26
POWER MANAGEMENT/SCHEDULING AGENT 27
RESOURCE PORTFOLIOS 29
LACCE COST OF SERVICE 35
COST OF SERVICE FOR LACCE OPERATIONS 35
POWER SUPPLY COSTS 35
NON-POWER SUPPLY COSTS 36
PRODUCTS,SERVICES,RATES COMPARISON AND ENVIRONMENTAL/ECONOMIC IMPACTS 43
RATES PAID BY SCE BUNDLED CUSTOMERS 43
RATES PAID BY LACCE CUSTOMERS 43
RATE IMPACTS 45
LOCAL RESOURCES/BEHIND THE METER LACCE PROGRAMS 46
IMPACT OF RESOURCE PLAN ON GREENHOUSE GAS(GHG)EMISSIONS 47
ECONOMIC DEVELOPMENT 48
Ordinance No.461
28
SENSITIVITY ANALYSIS 52
LOADS AND CUSTOMER PARTICIPATION RATES 53
SCE RATES AND SURCHARGES 53
SENSITIVITY RESULTS 54
RISKS 55
SCHEDULE 55
SUMMARY AND RECOMMENDATIONS 57
RATE IMPACTS AND COMPARISONS 57
RENEWABLE ENERGY IMPACTS 58
ENERGY EFFICIENCY IMPACTS 58
ECONOMIC DEVELOPMENT IMPACTS 58
IMPACT OF RESOURCE PLAN ON GREENHOUSE GAS(GHG)EMISSIONS 59
SUMMARY 60
APPENDIX A-CITIES/COUNTIES EVALUATING CCA FEASIBILITY 61
APPENDIX B-CCA FUNDING OPTIONS PREPARED BY PUBLIC FINANCIAL MANAGEMENT,INC 62
APPENDIX C-PROFORMA ANALYSES 67
APPENDIX D-GLOSSARY 70
Ordinance No.461
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Executive Summary
Background
The California legislature passed AB 117 in 2002 (amended in 2011 by SB 790) allowing all Cities,
Counties, or groups of Cities and Counties to provide an electric power supply source to customers
within their jurisdictions that are currently served by Southern California Edison, Pacific Gas &
Electric or San Diego Gas & Electric. Community Choice Aggregation (CCA) or Community Choice
Energy (CCE) is a customer opt-out program where the CCA provides power supply and behind the
meter services, and the incumbent IOUs provide transmission and distribution (wires) service.
This Business Plan (Plan) evaluates the prudency of forming a CCA within the County of Los Angeles
(County), the Los Angeles Community Choice Energy (LACCE). The proposed LACCE will provide
power supply and behind the meter services, and Southern California Edison (SCE) will provide
transmission and distribution services. Customers are part of the LACCE program until they
proactively opt-out. This Plan estimates LACCE's power supply costs, administrative costs, electric
loads, and future retail rates and compares LACCE's rates to the incumbent SCE. These forecast
rates are compared to determine if the proposed LACCE can offer competitive rates, better
products and superior customer service while also improving the environment and creating local
jobs.
Description of LACCE
The proposed LACCE may include the unincorporated areas of the County and a number of Cities
within the County. The unincorporated County average annual energy is 440 aMW (average
Megawatts) and 900 MW peak while the total County potential service area average annual energy
is estimated at 3,000 aMW and 7,000 MW peak. Energy consumption for the entire County area
served by SCE is equal to more than 30 percent of SCE's total retail load.
For this Plan, it is assumed that service will be offered to customers in three phases. Phase 1 will
include the County's own municipal facilities residing within the unincorporated County areas. In
Phase 2, all customers located in the unincorporated County will be included in LACCE. Finally,
service to customers from the Cities within the County will begin under Phase 3. Exhibit ES-1
summarizes this phased approach to forming LACCE, and the number of customers and amount of
load attendant with each phase.
Ordinance No.461
30
Exhibit ES-1
Participation Schedule
Average LACCE
Customer Peak Load Load Annual
Phase Start Eligibility Accounts (MW) aMW Revenues
Phase 1 January 2017 LA County Facilities 1,728 40 20 $25M
within Unincorporated
Area
Phase 2 July 2017 All Customers in 306,930 900 440 $180M
Unincorporated LA
County
Phase 3 To Be Determined All Individual Cities 1,497,747 7,000 3,000 $1,200M
Depending on the interest from Cities located in the County, Phase 1 and Phase 2 may also include
customers from individual Cities. However, because of the number of Cities and the size of their
associated loads, a phasing of implementation was assumed for this Plan. This phasing strategy
enables LACCE to manage any start-up and operational issues before full scale operations are
undertaken. In addition, this phasing strategy will allow LACCE's third party electricity suppliers,
scheduling agents and data management entities to ramp up power supply procurement and bill
processing over several months. Because it is not yet clear which Cities are interested in joining
LACCE, this Plan explores the prudency of the first two phases being undertaken over a 20-year
forecast period. It is anticipated that the results of this Plan are scalable as additional Cities join
LACCE. Adding more customers than assumed in the Plan will increase revenues and further reduce
LACCE rates.
By the end of Phase 2, LACCE is projected to serve a potential of over 300,000 retail customers and
have annual electricity sales potential of over 3,800 GWh (Gigawatt-hours). Annual revenues to
LACCE during Phase 2 operations are projected to be approximately$180 million.
Governance
The feasibility, analysis and development of LACCE is currently being conducted by the Office of
Sustainability within the County's Internal Services Department. While LACCE could, in theory, be
an organization operated within the County's existing governance, it is anticipated that a JPA will
be formed to provide the legal structure of LACCE. A JPA provides a more flexible framework for
LACCE and historically has been the preferred structure for an organization like LACCE. Additionally,
a JPA provides financial risk mitigation for its local government members.
Given the above, a key next step in the formation of LACCE is the creation of the JPA (created when
two jurisdictions agree to join the JPA). Initiating LACCE operations will then require a governing
authority to execute service contracts for LACCE formation and operations.
Alternatively, while a JPA is being finalized and implemented, the Office of Sustainability could
manage Phase I operations of LACCE, if directed by the Board of Supervisors.
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Risks
All businesses face risks and uncertainty. For LACCE, the major risks will be operational and
regulatory. These risks are dealt with extensively later in the Plan. In summary,the Plan concludes
that these risks are manageable and that no reasonable set of circumstances will result in LACCE's
rates being higher than SCE's for comparable products.
Plan Results
This Plan evaluates the cost and resulting rates of operating LACCE, and compares these rates to a
rate forecast for SCE. The analysis begins with a 20-year forecast of electrical loads and customers,
incorporates several power supply resource portfolio options, and allows for the sensitivity testing
of input assumptions. LACCE customers will see no obvious changes in electric service other than
a lower price and increased renewable resources in their power supply resource mix. Customers
will pay the power supply charges set by LACCE and no longer pay the costs of SCE power supply.
In addition to paying LACCE's power supply rate, LACCE customers will pay the SCE delivery (wires)
rate and all other non-power supply related charges on the SCE bill to include Franchise Fees and
Utility User Taxes.
LACCE will establish rates sufficient to recover all costs related to operation of the CCE. It is
anticipated that LACCE's rate designs initially will mirror the structure of SCE's rates so that rates
similar to SCE's can be provided to LACCE's customers. In setting rates, the Plan's financial analysis
assumes the customer phase-in schedule noted above and assumes that the implementation costs
are largely financed via a start-up loan.
The first consequence for forming LACCE is the retail rate impact as illustrated on ES-2. ES-2 shows
SCE's current total bundled rates of 28 percent renewable power compared to three LACCE rate
options. Bundled rates are the "all in" price for electricity delivered to the customer's meter. The
Plan's Resource Portfolio Standard (RPS) rate assumes renewable energy is 28 percent of LACCE's
initial power supply portfolio and increased per the State's RPS mandate.
For reference, the column headers noted on ES-2 are summarized below.
• RPS Bundled — LACCE rates with the same share (28 percent) of renewables as SCE's current
power supply.
• 50%Green Bundled Rate— LACCE rates with 50 percent renewable power.
• 100%Green Bundled Rates—LACCE rates with 100 percent renewable power.
A rate schedule comparison of LACCE's rates and SCE's rates follows.
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Exhibit ES-2
Indicative Rate Comparison in C/kWh
SCE Bundled LACCE RPS LACCE 50% LACCE 100%
Rate Class Customer Type Rate* Bundled Rate Green Bundled Green Bundled
Rate Rate
Residential Domestic 17.1 16.2 16.4 18.2
GS-1 Commercial 16.6 15.7 15.9 17.7
GS-2 Commercial 15.8 15.0 15.2 16.9
GS-3 Industrial 14.5 13.8 13.9 15.5
PA-2 Public Authority 12.6 12.0 12.1 13.4
PA-3 Public Authority 10.4 9.9 10.0 11.1
TOU-8 Secondary Domestic 13.1 12.4 12.6 14.0
TOU-8 Primary Commercial 11.7 11.1 11.2 12.5
TOU-8 Substation Industrial 7.5 7.1 7.2 8.0
Total LACCE Rate Savings 1 5.4% 4.1% (6.3%)
*SCE bundled average rate based on Table 3 in Advice 3319-E-A.
As can be seen above, the LACCE RPS residential rate is 0.9C/kWh or 5.4 percent lower than what
SCE currently offers with an equal amount of renewable power (28 percent). The LACCE residential
rate with 50 percent renewable power (compared to SCE's 28 percent) is 0.7C/kWh or 4.1 percent
lower for roughly twice the amount of green renewable power.The LACCE residential rate with 100
percent green power (compared to SCE's 28 percent) is 1.1C/kWh or 6.3 percent higher, but this
additional amount comes with almost four times more renewable power than the comparable SCE
rate.
As an alternative to its standard rates with 28 percent renewable power,SCE also offers rates which
feature 50 percent and 100 percent renewable power. For the residential customers, SCE estimates
energy costs to be 3.5 cents per kWh higher for each kWh served on the green rate. The LACCE
rates for 50 percent and 100 percent renewable power for residential customers are therefore
estimated at 12-13% percent lower than SCE's.
The rates calculated under this Plan are for comparison to SCE rates only. Under formal operations,
the LACCE governance will determine the actual rates to be offered to customers. For example,
LACCE may decide to offer the 50% renewables rate as the base tariff to customers if the
environmental benefits far outweigh a minor difference in cost compared to the RPS base case.
Finally, it should be noted that these rate comparisons assume all savings will go towards rate
reductions. It is likely that the LACCE governing body may opt to place some of these savings into
a financial reserve account for use at other times when needed and/or to accelerate the payoff of
start-up and initial operations financing.
Renewable Energy Impacts
A second consequence of forming LACCE will be an anticipated increase in the proportion of energy
supplied by renewable resources used by LACCE customers. The Plan includes procurement of
renewable energy sufficient to meet 50 percent or more of LACCE customer's electricity needs at
start up. The majority of this renewable energy will be met by renewable energy purchased on the
wholesale market or newly constructed renewable resources. By 2020, SCE must procure a
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minimum of 33 percent of its customers' annual electricity usage from renewable resources due to
the State's RPS mandate and the Energy Action Plan requirements of the California Public Utilities
Commission (CPUC). In contrast, LACCE customers will target 50 percent renewable power by 2017,
which will come from new and some local renewable resources.
Energy Efficiency Programs
A third consequence of the Program will be an increase in energy efficiency program investments
and activities. The existing energy efficiency programs administered by SCE will not change as a
result of LACCE. LACCE customers will continue to pay the Public Goods Charges to SCE. This charge
funds energy efficiency programs for all customers, regardless of power supply provider. The
energy efficiency programs ultimately planned by LACCE will be in addition to the level of energy
efficiency investment currently provided by SCE. Thus, LACCE has the potential to increase energy
savings with an attendant reduction in emissions due to expanded energy efficiency programs.
LACCE will likely establish a program which offers a combination of retail tariffs, rebates, incentives
and other bundled offerings intended to increase customer participation in demand-side
management programs including: renewable distributed generation, energy storage, energy
efficiency, demand response, electric vehicle charging, and other clean energy benefits defined as
Distributed Energy Resources (DER). LACCE will work with State agencies and SCE to promote
deployment of DERs in specific and targeted locations throughout SCE's distribution grid, and
preferably within the County, in order to help support efficient grid operations and maintenance as
part of the development of the future "smart grid."
The Southern California Regional Energy Network (SoCaIREN), administered by the Office of
Sustainability and authorized by the California Public Utilities Commission (CPUC) as an
independently administered energy efficiency program in 2012, will serve as a platform for
providing the services described above as it already receives funding under the CPUC's Energy
Efficiency Program and is active in current CPUC proceedings designed to accelerate the
implementation of local DERs.
Economic Development
The fourth consequence of LACCE will be significant economic development. So far, the analyses
contained in this Plan focused on the direct effects of forming LACCE. However, in addition to these
direct effects,the formation of LACCE will create indirect economic effects. These include increased
local investments, increased disposable income due to bill savings, and improved environmental
and health conditions.
Exhibit ES-3 shows the economic impact resulting from $20 million in electric bill savings across the
County. The $20 million rate savings represents the estimated bill savings per year achievable by
LACCE once Phase 3 operations begin. Based upon a macroeconomic input/output model
employed for this Plan, it is estimated that these savings will create approximately 211 additional
jobs in the County and over $9.6 million in labor income. It is also estimated that the total value
added will be approximately$15.9 million and output close to $24.2 million.
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Exhibit ES-3
$20 Million Rate Savings Effects on County Economy
Impact Type Employment Labor Income Total Value Added Output
Direct Effect 98.3 $3,674,939 $5,376,863 $7,099,612
Indirect Effect 10.4 $608,838 $1,057,593 $1,677,591
Induced Effect 102.1 $5,319,262 $9,472,599 $15,391,851
Total Effect 210.7 $9,603,040 $15,907,056 $24,169,054
In addition to increased economic activity due to electric bill savings, potential local projects can
also create job and economic growth within the County. As an example of the macroeconomic
activity caused by local DER deployment, this Plan assumes the installation of 50 crystalline silicon,
fixed mount solar systems with nameplate capacities of 1 MW each for a total capacity of 50 MW.
Overall, the building of a 50 MW solar project is projected to create $87 million in earnings and
$188 million in output (GDP) in the local economy along with 1,636 jobs during construction and 14
full-time jobs ongoing. It is anticipated that LACCE will ultimately install a number of larger local
solar projects such as the one described. LACCE will need between 2,000 — 3,000 MW of solar at
build-out. As such, the total economic benefit of LACCE's renewable resource could be 40 — 60
times those estimated above. Local clean projects development under LACCE may serve as a
platform for accelerating local hiring programs and job training programs for underserved labor
sectors and communities.
Green House Gas Impacts
The fifth consequence of forming LACCE will be significant environment benefits. The share of
renewable power in SCE's power supply portfolio is currently 28 percent' and is scheduled to shift
to 33 percent by 2020. LACCE is committed to reductions in greenhouse gas emissions. If LACCE
achieves its 50 percent RPS target at start-up, GHG emissions reductions attributable to LACCE
operations in 2019 will range from 289,080 to 505,890 tons CO2 equivalent (CO2e) per year relative
to SCE's projected resource mix over the same period. Exhibit ES-4 details these reductions.
Exhibit ES-4
Baseline Comparison of GHG Reduction by LACCE
2017 2018 2019
Forecast Renewables(50%Renewables) 1,438,275 1,459,854 1,459,854
LACCE(MWH)—Phase 2
LACCE RPS(MWH)—Phase 2 730,029 737,154 737,154
Additional Green Power(MWH) 708,246 722,700 722,700
CO2 reduction—Low(Metric Tons of CO2e) 283,298 289,080 289,080
CO2 reduction—High (Metric tons of CO2e) 495,772 505,890 505,890
1 http://www.cpuc.ca.gov/RPS_Homepage/
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These reductions in GHG emissions associated with LACCE operations are significant. Assuming only
Phase 2 loads(all unincorporated County loads)are being met by LACCE, CO2e emissions associated
with in-County electricity use will be reduced by 1-2 percent. At full Phase 3 build-out, CO2
emissions associated with in-County electricity use will be reduced roughly 12-25 percent by LACCE
operations.
Summary
This Plan concludes that the formation of a CCA in Los Angeles County is financially prudent and will
yield considerable benefits for the County's residents and businesses. These benefits include at
least a 4 percent lower rate for electricity than is charged by SCE and roughly twice the amount of
renewable resource deployment. With the achievement of Phase 2 operations, LACCE will reduce
GHG emissions by as much as 500,000 tons of CO2e per year, add hundreds of jobs, generate over
$24 million in additional GDP, and give the County and its residents local control over their power
supply and distributed energy resource programs. At full build-out (Phase 3), LACCE will reduce in-
County generation-related greenhouse gases by as much as 25 percent and total GHGs in the
County by 6%. Finally, there is no reasonable set of risk-related circumstances that will result in
LACCE's rates being higher than SCE's rates for comparable products.
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Introduction
Background
California's legislature passed AB 117 in 2002 (amended in 2011 by SB 790) allowing all Cities,
Counties, or groups of Cities and Counties to provide electric service to customers currently served
by Investor-Owned Utilities (IOUs). Community Choice Aggregation (CCA) is the legislative
organization empowered to provide this service. A CCA is a customer opt-out program where the
CCA provides power supply and behind the meter services, and the incumbent IOU provides
transmission and distribution (wires) service. This legislation states that CCA will enable California
to experience more competitive electricity rates, a more renewable power supply mix, and growth
in local resources and associated economic activity. Currently, there are five CCAs operating in
California and these utilities offer competitive rates for power supply that have a higher percentage
of renewable resources. They have also proven to promote local economic activity and their
associated benefits.
Several other California Cities and Counties are currently evaluating the feasibility of CCA formation
within their jurisdictions. This information can be found in Appendix A.
There are several potential benefits of the CCA model in addition to competitive rates. Other
benefits include local control over energy resources selection including renewable local projects,
energy efficiency and a reduction in greenhouse gases(GHG). In addition,CCAs can minimize power
supply rates and maximize renewable energy utilization with the attendant local jobs in the local
community.
Objective
This Business Plan (Plan) evaluates the feasibility of forming a CCA within the County of Los Angeles
(County) named the Los Angeles Community Choice Energy(LACCE). The proposed CCA will provide
power supply and behind the meter services, and Southern California Edison (SCE) will provide
transmission and distribution (wires) services. This Plan estimates LACCE's power supply costs,
administrative costs, electric loads, and future retail rates for the proposed LACCE and incumbent
Investor-Owned Utility (IOU), Southern California Edison (SCE). These forecast rates are compared
to determine if the proposed LACCE can offer competitive rates, better products and superior
customer service. A sound financial and operational foundation for LACCE must be achievable
before the other desirable attributes of a CCA can be enjoyed.
LACCE Description
LACCE, as proposed, may include the unincorporated areas of the County and a number of Cities
within the County. Unincorporated County average annual energy use is 440 aMW with a 900 MW
peak while the total Plan area average annual energy use is estimated at 3,000 aMW with a 7,000
MW peak. Energy consumption for the entire LACCE area equals more than 30 percent of SCE's
current retail loads.
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For this Plan, it is assumed that service will be offered to customers in three phases. Phase 1 will
include the County's own facilities residing within the unincorporated County areas. In Phase 2, all
customers located in the unincorporated County will be included into LACCE. Finally, service to
customers from the Cities within the County will begin under Phase 3 and after LACCE is completely
operational. However, Cities that are ready to participate early will be eligible under Phases 1 and
2. Exhibit 1 summarizes this phased approach to starting LACCE and the amount of load attendant
with each phase.
Exhibit 1
Participation Schedule
Average LACCE
Customer Peak Load Load Annual
Phase Start Eligibility Accounts (MW) (MWa) Revenues
Phase 1 January 2017 LA County Facilities 1,728 40 20 $25M
within Unincorporated
Area
Phase 2 July 2017 All Customers in 306,930 900 440 $180M
Unincorporated LA
County
Phase 3 To Be Determined All Individual Cities 1,497,747 7,000 3,000 $1,200M
Customer Participation Schedule
Depending on the interest from Cities located in the County, Phase 1 and Phase 2 may include
customers from individual Cities; however, because of the number of Cities and the size of their
associated loads, a phasing strategy is assumed for this Plan. This phasing strategy enables LACCE
to address any start-up and operational issues before full scale operations are undertaken. In
addition,this strategy will allow LACCE's third party electricity suppliers,scheduling agents and data
managers to ramp up their activities over several months.
Because it is not yet clear when Cities will join LACCE, this Plan explores the feasibility of only the
first two phases. It is anticipated that the results of this Plan are scalable as additional Cities join
LACCE. However, a few of the key statistics and benefits that LACCE provides have also been noted
under full-scale participation of Phase 3. Additional load from other Cities will increase LACCE's
revenues and lower overall rates.
By the end of Phase 2, LACCE is projected to serve a potential of over 300,000 retail customers and
have annual electricity sales potential of over 3,800 GWh. Annual LACCE revenues at Phase 2 build-
out are projected to be $180 million. At full build-out for the entire County, gross revenues of$1.2
billion are forecast. The breakdown of projected sales in Phase 2 by major customer class is shown
in the following Exhibit 2.
•
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Exhibit 2
Retail Energy Share by Rate Class
RETAIL ENERGY SHARE BY RATE CLASS
UNINCORPORATED COUNTY
Public Authority,3%
Industrial,12%
Domestic,55%
General Service,29
Street Lighting,1%
Summary of LACCE's Proposed Governance and Operations
In the future, LACCE will likely be operated under the terms of a Joint Powers Agreement (JPA),
which will promote,develop,and conduct electricity-related projects and programs for the County's
residences and businesses. The JPA agreement will dictate the governance provisions of LACCE. A
description of LACCE operations and governance is described below.
LACCE activities will be overseen by the JPA's Board of Directors (Board). This Board will have
primary responsibility for managing all aspects of LACCE programs. Operations of LACCE programs
will be the responsibility of an Executive Director, appointed by LACCE's Board. The Executive
Director will manage staff, contractors and third party providers, in accordance with the general
policies established by the Board. LACCE has responsibilities over the functional areas of Finance,
Legal/Regulatory, and Operations. LACCE will utilize a combination of internal staff and contactors.
Certain specialized functions are needed within LACCE operations, namely those of electric supply
and customer billing management.
If LACCE transitions most of its administrative and operational responsibilities to internally staffed
positions sometime during Phase 2 operations, LACCE will have a full time staff of approximately 15
— 20 employees to perform its responsibilities, primarily related to program and contract
management, legal and regulatory, finance and accounting, energy efficiency, marketing and
customer service. Technical functions associated with managing and scheduling power suppliers
and those related to retail customer billings will likely be performed by an experienced third party
contractor. The proposed organization chart for LACCE is provided below.
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Exhibit 3
Organization Chart
Executive Director
Administrative
Assistant
Assistant Executive Policy& Human Resources
Regulatory Manager
Director Manager
f ■ I 1
Power Finance and Rate .ales&Marketin:i Regulatory
Procurement Manager Manager IT Manager " Analyst HR Specialist
Consultant
Accounting& _ Energy Efficiency L IT Specialist Regulatory
Billing Analyst •rogram Manage Consultant
▪ Rates Analyst 2 Account Regulatory
Representatives Attorney
Data Communication
Management& Specialists
Billing Consultant
It is estimated that LACCE will need a bridge loan of roughly$10 million to initiate LACCE and provide
the working capital needed in Phase 1. Working capital requirements will increase to approximately
$40 million for Phase 2. Options for acquiring this funding are described later in the Plan.
Plan Methodology
This Plan evaluates the cost and resulting rates of operating LACCE and compares these rates to a
SCE rate forecast. This pro forma 20-year feasibility analysis models the following cost components:
• Power Supply Costs:
• Wholesale purchase
• Renewable purchases
• Procurement of resource adequacy capacity
• Other power supply and charges
• Non-Power Supply Costs:
• Start-up costs
• LACCE staffing and administration costs
• Consulting support
• SCE and regulatory charges
• Financing costs
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■ Pass-Through Charges from SCE:
• Transmission and distribution charges
• Power Cost Indifference Adjustment (PCIA) Charge
• Other SCE non-bypassable charges
The modeled information above is used to determine the retail rates for LACCE. LACCE rates are
then compared to the SCE projected rates for LACCE service area.
Plan Uncertainties
The results of this Plan are subject to uncertainties. These uncertainties are evaluated in the Plan's
sensitivity analysis. The list below provides a discussion of the key uncertainties of this Plan.
■ Market Price Forecasts — Market prices (and forecasts) are continually changing. The market
price forecasts for electricity and natural gas utilized in this Plan are based on the best currently
available information regarding future natural gas and electricity prices, and have been
confirmed by recent wholesale power transactions in southern California. These types of
forecasts vary over time. Thus, a range of market price forecasts are evaluated in the Plan's
sensitivity analysis.
■ Rate Forecasts — The Plan forecasts both LACCE and SCE rates over a 20-year study period.
These forecasts are based on current information regarding inflation and other cost drivers.
Unexpected impacts on rates are discussed in more detail in the Plan's sensitivity analysis.
■ Forecasted Load and Customer Growth—The Plan bases the load forecasts on customer growth.
Each of these forecasts includes a level of uncertainty. To illustrate the load uncertainty, low,
medium, and high load forecasts are developed for the Plan's sensitivity analysis.
■ Regulatory Risks—Unforeseen changes in legislation (California Public Utility Commission, State
legislation and Federal Energy Regulatory Commission) may impact the results of this Plan.
Sensitivities on these risks are also provided.
This sensitivity analysis shows that LACCE rate could be greater than SCE rates if:
■ The PCIA becomes larger by orders of magnitude
■ LACCE loads are much less than forecast
■ Wholesale market prices are much less than current experience
Each of these three scenarios has a low risk of actually occurring. For example, wholesale market
prices for natural gas/electricity are at all-time lows. The probability of any significant further
lowering of these prices is judged to be very small. The PCIA level should be fairly stable going
forward as regulatory remedies are in play to stabilize the PCIA. Additionally, the CCA vigilance in
this area has increased markedly. A relatively high customer opt-out percentage has been assumed
in this Plan as compared to those experienced by operating CCAs. It is very unlikely LACCE loads
will not meet or exceed those assumed in the Plan. Finally, the California legislature promulgates
energy legislation with some regularity. Most recently, SB 350 was passed which requires periodic
filings by all utilities to document their respective power procurement strategies and requires all
utilities to procure a large amount of power with contract terms greater than 10 years. While these
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new requirements may be viewed as overly prescriptive, they apply to all utilities and should not
affect the relative competitiveness of LACCE vis-a-vis SCE.
Plan Organization
This Plan is organized into the following main sections:
■ Load Requirements
■ Power Supply Strategy and Costs
■ LACCE Cost of Service
■ Products, Services, Rates Comparison and Environmental/Economic Considerations
■ Sensitivity Analysis
■ Summary and Recommendations
These Appendices are referenced throughout the balance of this Plan.
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Load Requirements
Rates paid by LACCE customers will vary depending on load levels, power supply mix, power
purchase strategy, stranded costs estimated via SCE's Power Cost Indifference Adjustment (PCIA),
and ultimately LACCE's implementation strategy. This section of the Plan provides an overview of
the forecast LACCE load levels. The other key areas noted above will be detailed in the remaining
sections of the Plan.
LACCE JPA Membership Participation Rates
For the purpose of this Plan, it has been assumed that the development of LACCE will occur using a
three-phase implementation structure. Phase 1 will include the County's own facilities within the
unincorporated County. Phase 2 will enroll all customers in the unincorporated County,while Phase
3 opens enrollment to all interested Cities within the County. Because the timing of Phase 3 is
uncertain, this Plan examines the feasibility of a LACCE covering only unincorporated LA County
(Phases 1 and 2). However, individual Cities could participate in LACCE starting in Phase 1 or Phase
2, if desired. This will require notification to LACCE of a City wishing to join that is early enough for
proper power supply and data management issues to be resolved.
Exhibit 4 summarizes this phased approach to starting LACCE and the amount of load attendant
with each phase.
Exhibit 4
Implementation Schedule
Average LACCE
Customer Peak Load Load Annual
Phase Start Eligibility Accounts (MW) (MWa) Revenues
Phase 1 January 2017 LA County Facilities 1,728 40 20 $25M
within Unincorporated
Area
Phase 2 July 2017 All Customers in 306,930 900 440 $180M
Unincorporated LA
County
Phase 3 To Be Determined All Individual Cities 1,497,747 7,000 3,000 $1,200M
LACCE Customer Participation Rates
Before customers are served by LACCE, they will receive two notices from LACCE that will provide
information needed to understand the terms and conditions of service from LACCE and explain how
customers can opt-out, if desired. These notices will be provided 60 and 30 days before CCA launch.
All customers that do not follow the opt-out process specified in the customer notices will be
automatically enrolled into LACCE. Customers automatically enrolled will continue to have their
electric meters read and will be billed for electric service by SCE. LACCE bill processed by SCE will
show separate charges for power supply procured by LACCE, all other charges related to delivery of
the electricity and other utility charges that will continue to be assessed.
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Subsequent to commencement of service, customers will be given two additional opportunities to
opt-out and return to SCE at 60 and 30 days after LACCE's launch. Customers that opt-out between
the initial switchover date and the close of the post enrollment opt-out period will be responsible
for LACCE charges for the time they are served by LACCE but will not otherwise be subject to any
charges for leaving LACCE. Customers that have not opted-out within sixty days of switchover to
LACCE service will be deemed to have elected to become a participant in LACCE.
This Plan anticipates an overall customer participation rate of 100 percent during Phase 1, as service
is being offered to County facilities. For Phase 2, it is assumed that approximately 75 percent of
residential customers and 65 percent of non-residential customers will remain with LACCE. These
opt-out assumptions are conservative estimates when compared to participation rates in other
CCAs. For operating CCAs in California, roughly 85 percent of the applicable customers have stayed
with the CCA. A sensitivity analysis is performed around this retail customer participation rate
assumption to illustrate the impact on LACCE rates of higher and lower participation rates.
Historical Consumption
SCE provided historical customer consumption and data for the County areas served by SCE. This
SCE data included non-coincident and coincident peak demands for the different rate classes plus
monthly kWh energy consumption. This data included information from all 82 CCA-eligible Cities
within the County plus the County's unincorporated areas. These data inputs provided the basis
for LACCE load forecasts. Exhibit 5 summarizes the rate schedules included in the SCE-provided
data.
Exhibit 5
Rate Schedules Included in SCE Load Data
Included Rate
Rate Class Schedules Rate Schedule Description
Residential DOM-S/M Domestic Service—Single-Family Dwelling or individually metered
Single-Family Dwelling in a Multifamily Accommodation
DOM-M/M Domestic Service — Multifamily Accommodation — Residential
Hotel—Qualifying RV Park
DOM-S/M-CARE Domestic Service—California Alternate Rates
Small General Service TOU-GS-1 Time-of-Use—General Service(<20 kW)
Medium General Service TOU-GS-2 Time-of-Use—General Service—Demand Metered (20—200 kW)
Large General Service TOU-GS-3 Time-of-Use—General Service—Demand Metered (200—500 kW)
Industrial/Large Power TOU-8-PRI Time-of-Use—General Service—Large—Primary Transmission
TOU-8-SEC Time-of-Use—General Service—Large—Secondary Transmission
TOU-8-SUB Time-of-Use—General Service—Large-Subtransmission
Small/Medium TOU-PA-2 Time-of-Use—Agricultural&Pumping—Small to Medium
Agricultural and Pumping
Large Agricultural and TOU-PA-3 Time-of-Use—Agricultural&Pumping—Large
Pumping
LS-1 Street and Highway Lighting — Unmetered Service — Company-
Street Lighting Owned
Traffic Control TC-1 Traffic Control Service
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Based on this data, there are 1,497,747 SCE electric customers within the County served by SCE.
Annual energy consumption for all of these customers was 26,290 GWh. Bundled customers (full
service) make up over 99 percent of total customer accounts and comprise approximately 86
percent of the total energy use. Direct access customers account for only 0.7 percent of customers,
but use nearly 16 percent of the annual energy. Exhibit 6 summarizes historic energy consumption
and customer accounts for SCE customers within the County.
Exhibit 6
Summary of Load Data by Customer Type
Customer Customer Accounts Annual Energy Use Energy Use
Customer Category Accounts (%of total) (MWh) (%of total)
SCE-Bundled Customers 1,497,747 99.3% 26,290,996 85.5%
Direct Access Customers 10,588 0.7% 4,465,290 14.5%
Total 1,508,335 100.0% 30,756,286 100.0%
Direct access customers purchase their power supply and other services from an electric service
provider (ESP), rather than the incumbent utility. In California, eligibility for DA enrollment is
currently limited to retail non-residential customers and enrollment is based on an annual lottery.2
Customers classified as taking service under direct access arrangements were not included in this
Plan, as it is assumed that these customers will remain with their current ESP5. Exhibit 7 shows
consumption and customer counts by rate class for SCE's bundled customers in the County.
Exhibit 7
Summary of Bundled Load Data by Rate Class
Customer Customer Accounts Annual Energy Use Energy Use
Rate Class Accounts (%of total) (MWh) (%of total)
Residential 1,242,505 83% 7,721,755 29.0%
Small General Service 200,197 13% 2,368,901 9.0%
Medium General Service 35,591 2% 5,344,593 20.0%
Large General Service 2,630 0.2% 2,656,395 10.0%
Industrial/Large Power 1,112 0.1% 7,372,587 28.0%
Small/Medium
Agricultural and Pumping 2,098 0.1% 289,617 1.1%
Large Agricultural and
Pumping 226 0.02% 215,097 0.8%
Street Lighting 8,195 0.5% 300,571 1.1%
Traffic Control 5,193 0.3% 21,290 0.1%
Total 1,497,747 100.0% 26,290,996 100.0%
Customers located in CCA-eligible Cities within the County account for approximately 80 percent of
SCE customers and 85 percent of annual energy usage in all of the County. Potential customers and
energy consumption by location are shown in Exhibit 8.
2 S.B.286(CA,2015-2016 Reg.Sess.)
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Exhibit 8
Summary of Bundled Load Data by Location
Location within Customer Customer Accounts Annual Energy Use Energy Use
LA County Accounts (%of total) (MWh) (%of total)
Cities 1,190,816 80% 22,448,984 85%
Unincorporated 306,930 20% 3,841,822 15%
Total County 1,497,747 100% 26,290,996 100%
In addition to the SCE consumption data, SCE provided annual consumption, annual revenue and
annual peak demands for County-owned buildings served by SCE. Exhibit 8 summarizes the energy
consumption and customer counts for County facilities located in the Cities and unincorporated
areas of the County. This data provides the basis for Phase 1 of LACCE's Implementation Plan.
Exhibit 9 shows that there are 3,358 total eligible County facilities in the County and these
customers use approximately 472,892 MWh of energy per year. The number of County accounts
are distributed nearly equally between Cities and unincorporated County areas, yet County
buildings in Cities account for over two thirds of annual County electrical consumption.
Exhibit 9
Summary of LA County Facility Load Data by Location
Customer Customer Accounts(% Annual Energy Use Energy Use(%
Location Accounts of total) (MWh) of total)
Cities 1,630 49% 298,027 63%
Unincorporated 1,728 51% 174,865 37%
Total 3,358 100% 472,892 100%
Exhibit 10 shows energy consumption and customer distribution by rate class for all County-owned
facilities. General service customers account for over half of the County customers (55 percent)
and 35 percent of County loads.
Exhibit 10
Summary of LA County Facility Load Data by Rate Schedule
Customer Customer Accounts Annual Energy Use Energy Use(%
Rate Class Accounts (%of total) (MWh) of total)
Domestic 71 2% 359 < 1%
Small General Service 1,361 41% 13,428 3%
Medium General Service 432 13% 81,666 17%
Large General Service 63 2% 69,606 15%
Industrial 30 1% 202,514 43%
Agricultural&Pumping 202 <1% 25,650 5%
Outdoor Lighting 11 < 1% 20 <1%
Street Lighting 340 10% 77,358 16%
Traffic Control 847 25% 2,290 < 1%
General Service Electric 1 <1% 0.2 <1%
Vehicle Charging
Total 3,358 100% 472,892 100%
Ordinance No.461
46
Since the County facilities data included annual totals only, assumptions were made to estimate
monthly energy and monthly peak demands. Load profiles have been created, based on monthly
loads for each rate schedule, from SCE-provided data. Load profiles were assigned to County
facilities based on rate schedule. The resulting monthly energy distribution is illustrated in Exhibit
11. Monthly energy and customer estimates, by rate class and facility location, were used to adjust
SCE data to avoid double-counting customers and energy when developing load forecasts.
Exhibit 11
Monthly Energy Use by Rate Class for Total County Facilities
50,000
45,000
40,000
35,000 �.
30,000
r i
25,000
20,000
15,000
10,000
5,000
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
•Domestic •Small General Service Medium General Service
■Large General Service si Industrial Agricultural&Pumping
•Outdoor Lighting •Street Lighting •Traffic Control
•GS Electric Vehicle Charging
Forecast Consumption and Customers
Upon enrollment of customers in each of LACCE's implementation phases, customers will be
switched over to service with LACCE on their next regularly scheduled meter read date. Forecast
loads are needed to estimate LACCE revenue and power supply costs. A range of load forecasts
have been developed at the rate class level for each phase of LACCE's operations.
Average energy use per customer for residential and general service customers has been
normalized to remove any abnormal weather impacts from the historic energy data. Going forward,
projections for customers enrolled in LACCE and retail energy consumption have been forecast to
increase at 1.5 percent per year. This forecast is based on the mid-case electricity demand forecasts
for the SCE planning area, as reported to the California Energy Commission (CEC).3 Hourly electric
3 Southern California Edison. California Energy Demand 2015 Revised-Mid Demand Case. December 2015.
Sacramento,CA:California Energy Commission.
Ordinance No.461
47
consumption and peak demands have been estimated based on SCE's hourly load profiles for each
customer classification.
The number of accounts served by LACCE at the beginning of each phase is shown in Exhibit 12.
Exhibit 12
Projected Customer Enrollments
Program Customers Phase 1 Phase 2
Domestic 43 286,656
Commercial 925 27,902
Industrial 10 135
Street Lighting&Traffic 686 1,288
Ag&Pump 64 986
Total 1,728 306,903
The forecast of service accounts(customers)served by LACCE for each of the next ten years is shown
in Exhibit 13, which reflects an estimated annual growth of 1.5 percent and excludes other Cities.
Exhibit 13
Projected Service Accounts
500,000
450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
0
2016 2017 2018 2019. 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
■Commercial ■Lighting&Traffic Control •Agricultural •Domestic •Industrial
The LACCE forecast of kWh sales reflects the roll-out and customer enrollment schedule shown
above. The annual electricity needed to serve LACCE retail customers increases from just over 50
GWh in the first year to over 3,134 GWh by 2025. Annual energy requirements are shown below in
Exhibit 14.
Ordinance No.461
48
Exhibit 14
Projected Annual Energy Requirements
2017 2018 2019 2020 2021 2022 2023 2024 2025
Retail Sales(MWh) 1,646,785 2,873,075 2,894,927 2,921,864 2,952,194 2,995,937 3,040,110 3,085,547 3,134,997
Losses(MWh) 105,353 198,565 200,173 202,091 204,226 207,276 210,312 213,442 216,846
Total Load
Requirements(MWh) 1,752,137 3,071,640 3,095,099 3,123,954 3,156,421 3,203,213 3,250,422 3,298,989 3,351,843
Renewable ResourceRequirement
In addition to estimating the potential retail loads and customers, current legislation requires that
a certain percent of annual retail electric sales be supplied from qualified renewable energy
resources.
SBX1-2 passed in April, 2011 established a 33 percent Renewable Portfolio Standard (RPS)
requirement by 2020 with certain procurement targets prior to 2020. SBX1-2 also defined three
types of renewable categories (or Buckets)that can be used to meet the RPS target.
Bucket 1 —Renewable resources located in California or out-of-state renewable resources that can
meet strict scheduling requirement ensuring deliverability into California. According to SBX1 2
there are no limits on Bucket 1 renewable resources.
Bucket2—Bucket 2 renewable resources are firmed or shaped renewable resources not necessarily
delivered to California, but an equivalent amount of energy is delivered from a different non-
renewable resource and then bundled with Renewable Energy Certificates (RECs). Bucket 2
resources are limited to annual maximum of 20 percent of total RPS procurement through 2016
and 15 percent through 2020.
Bucket 3 — Bucket 3 consists of unbundled Renewable Energy Certificates (RECs) which are
separated from the actual electric energy. Bucket 3 resources are limited to an annual maximum
of 15 percent of total RPS procurement through 2016 and 10 percent through 2020.
In addition, SB350 increased the RPS requirement to 50 percent by 2030. At this time, the amount
of REC's that can be used to meet the 50 percent RPS requirement has not been finalized.
Exhibit 15 provides an overview of the RPS requirements until 2030.
Ordinance No.461
49
Exhibit 15
California RPS Requirements as a Percent of Total Power Supply
RPS Requirements
60.03'0
50.0%
40.0% -
30.0%
200%
10.0%
0.0%
2016 2020 2024 2027 2030
■Bucket 1 ■Bucket 2 ■Bucket 3
LACCE's Plan has been developed assuming LACCE will meet a 50 percent RPS target as soon as
possible through contracts, distributed generation and local resources.
LACCE will exceed SCE's renewable energy percentage from the first day of its operations when it
meets its 50 percent goal. LACCE will therefore significantly exceed the minimum RPS requirements
and significantly exceed the renewable power share provided by SCE.
Resource Adequacy Requirements
In addition to determining the renewable resource requirement, LACCE will also need to
demonstrate it has sufficient physical power supply capacity to meet its projected peak demand
plus a 15 percent planning reserve margin. This requirement is in accordance with resource
adequacy regulation administered by the CPUC and the California Energy Commission (CEC).
The CPUC's resource adequacy standards applicable to LACCE require a demonstration one year in
advance that LACCE has secured physical capacity for 90 percent of its projected peak demand for
each of the five months May through September, plus a minimum 15 percent reserve margin. On a
month-ahead basis, LACCE must demonstrate 100 percent of the peak load plus a minimum 15
percent reserve margin.
The Plan's load forecast estimates capacity needs, including resource capacity requirements, to be
used for the power supply cost forecasting.
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Power Supply Strategy and Costs
This section of the Plan provides a discussion of the power supply resource cost forecasts, potential
power supply strategies that could be implemented by LACCE and provides portfolio pricing based
on the loads projected for LACCE.
LACCE will be charged with developing both short(one and two-year)and long-term (five to twenty
years) resource plans. LACCE will develop the resource plan under the guidance provided by the
Joint Power Agency (JPA), in compliance with California law, and other requirements of California
regulatory bodies (CPUC and CEC).
Long-term resource planning includes load forecasting and supply planning on a 10-to 20-year time
horizon. LACCE's planners will develop integrated resource plans that meet their supply objectives
and balance cost, risk, and environmental considerations. Integrated resource planning considers
demand side energy efficiency and demand response programs as well as traditional supply options.
LACCE will require a planning function even if the day-to-day supply operations are contracted to
third parties. This will ensure that local preferences regarding the future composition of supply and
demand resources are planned for, developed and implemented.
Resource Strategy
LACCE should seek to maximize the use of local, cost-effective renewable generation resources in
its resource plan. The ability to invest capital in power supply and demand-side resources using tax-
exempt financing is an important factor in LACCE's ability to increase the use of renewable energy
while offering rates that are competitive with SCE. Power purchases from renewable and non-
renewable resources will supply the remaining majority of the resource mix. LACCE's electric
portfolio will be managed by a third party electric supplier,at least during the initial implementation
period. Through a power services agreement, LACCE will obtain full service requirements electricity
for its customers, including providing for all electric, ancillary services and the scheduling
arrangements necessary to provide delivered electricity.
Resource Costs
For this Plan, individual resource costs are estimated and other energy providers based on current
market condition, recent power supply contracts for renewable energy as well as a review of the
applicable regulatory requirements.
Market Purchases
Natural gas-fired power plants are typically the marginal power supply resource that sets the
electricity market price in southern California and elsewhere in the Western Energy Coordinating
Council (WECC) footprint. WECC guides power supply resources west of the Rocky Mountains. As
the market price of electricity is usually set by the cost of the marginal unit, a wholesale market
price forecast has been developed using a forecast of natural gas prices and the projected
relationship between gas price and electricity price (also defined as market-implied heat rates or
Ordinance No.461
51
spark spreads). The projected market-implied heat rates reflect the average efficiency of gas-fired
power plants in California. Projected heat rates are based on historic market-implied heat rates
which are calculated by dividing historic southern California (SP15) wholesale market prices by
historic southern California natural gas prices. A natural gas price forecast has been developed
based on NYMEX forward gas prices for the Henry Hub trading hub and southern California basis
differentials. Projected market heat rates have then been applied to the southern California natural
gas price forecast to calculate a wholesale electric market price forecast for southern California.
The following steps have been taken to produce the wholesale electric market price forecast:
1. Forward prices for natural gas at Henry Hub are available through June 2025. A 3.5 percent
annual growth rate is assumed after June 2025.
2. The southern California basis differential is used to adjust the Henry Hub forward prices to
southern California prices. Southern California forward natural gas prices are equal to NYMEX
forward prices (Henry Hub) plus the southern California basis. The southern California basis
forward curve is available through December 2020. After December 2020, the monthly
southern California basis is assumed to increase at 4 percent.
3. Projected monthly market-implied heat rates are multiplied by forecast southern California
natural gas prices to calculate forecast southern California wholesale market prices.
4. Projected heat rates are based on historic heat rates (southern California wholesale electricity
prices divided by SoCal natural gas prices).
5. Monthly market-implied heat rates are held constant in all years.
6. Forecast southern California prices are benchmarked against other market price forecasts.
Based on the methodology detailed above, southern California wholesale market prices are
projected to escalate annually at an average rate of 3.9 percent over 2017 through 2036.
Exhibit 16 shows the forecast southern California natural gas prices.
Exhibit 16
Forecast SoCal Natural Gas Price($/MMBtu)
5.0
4.5
4.0
3.5
3.0
2.5
2.0
1.5
1.0
05
00
n W 0o Ol Ol Ol O O N N N M m V 71-
<-1
<-1 r-1 c-I .-1 rl N N N N N N N N N N N N N
N U >, L OD 6 6 _6 6 Tm p Q v 2, aJ (o O %1 ro
z < 0 O2 a z 0
2
Ordinance No.461
52
Exhibit 17 shows the resulting monthly southern California wholesale electric market price forecast.
The levelized value of market prices over the study period is $39.5/MWh (2016 $) assuming a 4
percent discount rate.
Exhibit 17
Forecast Southern California Wholesale Market Prices($/MWh)
70
60
if?
50
40
30
20
10
O N Co of O 1--1 N N M V Lfl l0 N N 00 Q1 O N N M Cr Ul tD
N N N N N N N N N N N N M M M M CO M M M
r 0) f6 CO 0 0/ � m O N C) la co0 v /a
z 1„ 2 g , z 2 g z v 2 g z 2
Wholesale power prices have been used to calculate balancing market purchases and sales. When
LACCE's loads are greater than its resource capabilities, LACCE's scheduling agent will schedule
balancing purchases and LACCE will incur balancing market purchase costs. When LACCE's loads
are less than its resource capabilities, LACCE's scheduling agent will transact balancing sales and
LACCE will receive market sales revenue. Balancing market purchases and sales can be transacted
on a monthly, daily and hourly pre-schedule basis.
Renewable Energy
The wholesale market prices shown above are for"brown" power(i.e., this product does not come
with any renewable energy credit (REC) attributes). The costs of renewable resources vary greatly.
Wind and solar levelized project costs vary from $35 to $60/MWh. Geothermal project costs can
vary from$70 to$100/MWh. The availability of off-shore wind and ocean power in the marketplace
is fairly minimal and, as such, these resources were not included in the assessment of renewable
energy market prices.
Based on a survey of renewable resources currently in operation and new projects coming on-line,
a base case renewable energy market price of$42/MWh has been determined. Renewable energy
prices may increase in the future as the demand for renewable energy increases due to California's
RPS. However, renewable prices are being driven down by solar project costs which have declined
sharply over the past few years and are expected to continue to decrease over the next 10 to 20
Ordinance No.461
53
years. Again, the renewable energy prices have been independently confirmed by current market
tenders in southern California.
Projected power costs in this Plan are calculated using the base case renewable energy market price
of$42/MWh. The amount of renewable energy purchased will be assumed to be equal to the RPS
requirements in the base case. A higher case of 50 and 100 percent renewable energy will also be
considered later in this Plan. In the "100 percent renewables" case the renewable energy market
price was increased to$52/MWh. The$42/MWh price was based on an assumption that renewable
purchases would be served almost exclusively with the output from solar projects. In the "100
percent renewables" case a higher price was assumed in recognition that a more diverse, and
therefore more expensive, renewable energy portfolio would be needed. As such,the $52/MWh is
a blend of projected solar, geothermal and wind project costs. This is a conservative assumption as
100 percent solar power procurement is likely an achievable objective for LACCE.
Renewable Energy Credits (RECs)
As noted earlier, California load serving entities must purchase renewable energy or attributes that
meet certain eligibility requirements across three categories or buckets. Each of the buckets
represents a different type of renewable energy and can be used to meet a specific percent of the
total.The shares of each bucket also changes over time. The three buckets and the type of energy
included in each bucket can be summarized as follows:
■ Bucket 1: In-state renewable generation
■ Bucket 2: Firmed and shaped renewable energy products from a generator that has its first
point of interconnection with a California Balancing Authority(such as the CAISO)
■ Bucket 3: Energy is not included with the RECs (also known as unbundled RECs)
Under the current guidelines, the amount of RECs procured through Buckets 1 and 2 is limited and
decreases over time. Historically, the first bucket has been the most expensive type of energy to
purchase and load serving entities were only procuring the minimum they need to meet the RPS
requirement. However, with the decrease in solar project costs, Bucket 1 has become relatively
less expensive (compared to Buckets 2 and 3).
RECs are not viewed as good for the development of new projects. In addition, the REC market is
not as liquid as it once was. For the Plan's base case, unbundled REC prices are assumed to increase
from $10/REC in 2017 to $20 in 2036 (3.7 percent annual escalation). Due to the decline in solar
project costs (to near $40/MWh), the cost of unbundled RECs to meet RPS requirements and
wholesale market purchases to meet load are negligible. Due to this shift in market dynamics,
Bucket 3 RECs are no longer the least expensive option (as they were historically).
The Plan assumes that LACCE will not rely on REC purchases to meet RPS requirements. The REC
market can, however, be used to balance RPS requirements with renewable energy acquisitions. If
LACCE is short of RECs in a given compliance year, RECs could be purchased to meet the
requirements. If the CCE is long on RECs in a given compliance year, surplus RECs could be sold.
Ordinance No.461
54
Transmission
LACCE will pay the CAISO for transmission congestion and ancillary services. Transmission
congestion occurs when there is insufficient capacity to meet the demands of all transmission
customers. Congestion refers to a shortage of transmission capacity to supply a waiting market,
and is marked by systems running at full capacity and still being unable to serve the needs of all
customers. The transmission system is not allowed to run above its rated capacities. Congestion is
managed by the CAISO by charging congestion charges in the day-ahead market. Congestion
charges can be managed through the use of Congestion Revenue Rights (CRR). CRRs are financial
instruments made available through a CRR allocation, a CRR auction, and a secondary registration
system. CRR holders manage variability in congestion costs. The CCE's congestion charges will
depend on the transmission paths used to bring resources to load. As such, the location of
generating resources used to serve LACCE load will impact these congestion costs.
The Grid Management Charge (GMC) is the vehicle through which the CAISO recovers its
administrative and capital costs from the entities that utilize the CAISO's services. LACCE's Grid
Management Charges are expected to near$0.5/MWh.
The CAISO performs annual studies to identify the minimum local resource capacity required in
each local area to meet established reliability criteria. Load serving entities receive a proportional
allocation of the minimum required local resource capacity by transmission access charge area, and
submit resource adequacy plans to show that they have procured the necessary capacity.
Depending on these results of the annual studies,there may be costs associated with local capacity
requirements for LACCE.
Because generation is delivered as it is produced and, particularly with respect to renewables can
be intermittent, deliveries need to be firmed using ancillary services to meet LACCE's load
requirements. Ancillary services will need to be purchased from the CAISO. Regulation and
operating reserves are described below.
■ Regulation Service: Regulation service is necessary to provide for the continuous balancing of
resources with load and for maintaining scheduled interconnection frequency at 60 cycles per
second (60 Hertz). Regulation and frequency response service is accomplished by committing
on-line generation whose output is raised or lowered (predominantly through the use of
automatic generating control equipment) and by other non-generation resources capable of
providing this service as necessary to follow the moment-by-moment changes in load.
■ Operating Reserves-Spinning Reserve Service: Spinning reserve service is needed to serve load
immediately in the event of a system contingency. Spinning reserve service may be provided
by generating units that are on-line and loaded at less than maximum output and by non-
generation resources capable of providing this service.
■ Operating Reserves — Non-Spinning Reserve Service: Non-spinning reserve service is available
within a short period of time to serve load in the event of a system contingency. Non-spinning
reserve service may be provided by generating units that are on-line but not providing power,
by quick-start generation or by interruptible load or other non-generation resources capable of
providing this service.
Ordinance No.461
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Based on a survey of ancillary service costs currently paid by CAISO participants, LACCE's ancillary
service costs are estimated to be near$5/MWh. The Plan's base case will assume the CCE's ancillary
service costs are $5/MWh in 2017, escalating by 1.5 percent annually thereafter. Serving a greater
percentage of load with renewables will likely result in increased grid congestion and higher
ancillary service costs. For this reason, the ancillary service costs have been increased in the 50
percent and 100 percent renewables cases included in this Plan. For the 50 percent renewables
case, ancillary service costs are assumed to be $5.5/MWh in 2017, escalating by 1.5 percent. For
the 100 percent renewables case, ancillary service costs are assumed to be $8/MWh in 2017,
escalating by 2.5 percent.
Power Management/Scheduling Agent
Given the likely complexity of LACCE's resource portfolio, LACCE will want to rely on a reputable
scheduling agent to economically manage LACCE's power purchases and wholesale market
transactions. LACCE's resource portfolio will ultimately include market purchases, shares of some
relatively large power supply projects, as well as shares of smaller, most likely renewable, resources
with intermittent output. Managing a diverse resource portfolio with metered loads that will be
heavily influenced by distributed generation will be one of the most important functions of LACCE.
As such, LACCE needs a dependable, established scheduling agent with a proven track record in the
industry. LACCE's scheduling agent will be one of its most important business partners.
LACCE should initially contract with a third party with the necessary experience (and balance sheet)
to perform most of LACCE's portfolio operation requirements. This will include the procurement of
energy and ancillary services,scheduling coordinator services,and day-ahead and real-time trading.
Portfolio operations encompass the activities necessary for wholesale procurement of electricity to
serve end use customers. These activities include the following:
• Electricity Procurement — assemble a portfolio of electricity resources to supply the electric
needs of LACCE customers.
• Risk Management—standard industry risk management techniques will be employed to reduce
exposure to the volatility of energy markets and insulate customer rates from sudden changes
in wholesale market prices.
• Load Forecasting—develop accurate load forecasts, both long term for resource planning, and
short-term for the electricity purchases and sales needed to maintain a balance between hourly
resources and loads.
• Scheduling Coordination—scheduling and settling electric supply transactions with the CAISO.
LACCE should approve and adopt a set of protocols that will serve as the risk management tools for
LACCE and any third party involved in LACCE portfolio operations. Protocols will define risk
management policies and procedures, and a process for ensuring compliance throughout the
organization. During the initial start-up period, the chosen full requirements electric suppliers will
bear the majority of risks and be responsible for their management. Development of protocols can
Ordinance No.461
56
take place during the first few months of LACCE operations to cover electricity procurement
activities.
A scheduling agent provides day-ahead and real-time power and transmission scheduling services.
Scheduling agents bear the responsibility for accurate and timely load forecasting and resource
scheduling including wholesale power purchases and sales required to maintain hourly
load/resource balances. A scheduling agent needs to provide the marketing expertise and analytical
tools required to optimally dispatch LACCE's surplus resources on a monthly, daily and hourly basis.
Inside each hour, the CAISO Energy Imbalance Market (EIM) takes over load/resource balancing
duties. The EIM automatically balances loads and resources every fifteen minutes and dispatches
the least-cost resources every 5-minutes. The EIM allows balancing authorities to share reserves,
and more reliably and efficiently integrate renewable resources across a larger geographic region.
Within an hour, metered energy (i.e. actual usage) may differ from supplied power due to hourly
variations in resource output or unexpected load deviations. Deviations between metered energy
and supplied power are accounted for by the EIM. The imbalance market is used to resolve
imbalances between supply and demand. The EIM deals only with energy, not ancillary services or
reserves (which are addressed in the next section).
The EIM optimally dispatches participating resources to maintain load/resource balance in real-
time. The EIM uses the CAISO's real-time market which uses Security Constrained Economic
Dispatch (SCED). SCED finds the lowest cost generation to serve the load taking into account
operational constraints such as limits on generators or transmission facilities. The five-minute
market automatically procures generation needed to meet future imbalances. The purpose of the
five-minute market is to meet the very short term load forecast. Dispatch instructions are
effectuated through the Automated Dispatch System (ADS).
The CAISO is the market operator that runs and settles EIM transactions. LACCE's scheduling agent
will submit LACCE's load and resource information to the market operator. EIM processes are
running continuously for every fifteen-minute and five-minute intervals, producing dispatch
instructions and prices.
Participating resource scheduling coordinators submit energy bids to let the market operator know
that they are available to participate in the real-time market to help resolve energy imbalances.
Resource schedulers may also submit an energy bid to declare that resources will increase or
decrease generation if a certain price is struck. An energy bid is comprised of a megawatt value and
a price. For every increase in megawatt level, the settlement price also increases.
The CAISO calculates financial settlements based on the difference between schedules and actual
meter data, and bid prices during each hour. Locational Marginal Prices (LMP) are used in
settlement calculations. The LMP is the price of a unit of energy at a particular location at a given
time. LMPs are influenced by nearby generation, load level, and transmission constraints and
losses.
LACCE's scheduling agent will need to forecast LACCE's hourly loads as well as LACCE's hourly
resources including shares of any hydro, wind, solar and other resources in which LACCE is a
Ordinance No.461
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participant/purchaser. Forecasting the output of hydro, wind and solar projects involves more
variables than forecasting loads. Scheduling agents already have models set up to forecast
accurately hourly hydro, wind and solar generation. Accurate load and resource forecasting will be
a key element in assuring LACCE's power supply costs are minimized.
A scheduling agent also needs to provide monthly checkout and after-the-fact reconciliation
services. This requires scheduling agents to agree on the amount of energy purchased and/or sold
and the purchase costs and/or sales revenue associated with each counterparty with which LACCE
transacted in a given month.
Based on conversations with scheduling agents currently working the CAISO footprint, the
estimated cost of scheduling services is in the$1 to$2/MWh range. For the base case,the Plan has
assumed a cost of$1.5/MWh or $2.4 million in 2017 after Phase 2 is operational and escalating at
2.5 percent annually.
Resource Portfolios
In order to develop pricing options for LACCE customers and evaluate the impact of varying levels
of renewable resources in LACCE's portfolios, three resource portfolios were developed: RPS
Portfolio, 50 percent renewable portfolio and 100 percent renewable portfolio.
Resource Options
For each of the resource portfolios, a combination of resources has been assumed in order to meet
the renewable target, resource adequacy targets, and ancillary and balancing requirements.
Exhibit 18 shows the 20-year levelized resource costs included in this Plan.
Exhibit 18
20-Year Levelized Cost
(2016$/MWH)
65.c
bC,c
60
50
a1.5 42.0
39.5
40
v -
jii
1,
Spot Market Market PPA Renewable Resources Brown Resources Local Renewables
Ordinance No.461
58
Exhibit 18 above includes both spot market and market PPA costs. It is assumed that these costs
are primarilyfor naturalgas resources although the specific resource source cannot be determined
8 p
from a spot market purchase. Market PPA costs are slightly greater than spot market costs in
recognition of the cost of the PPA supplier absorbing the market price risk associated with providing
a long-term PPA contract price.
The capacity factor for market PPA purchases is assumed to be 100 percent (flat monthly blocks of
power). The capacity factor for renewable resources and local renewables is assumed to be 33
percent. The capacity factor for non-renewable resources is assumed to be 80 percent. As noted
above, the cost of renewable resources was increased from $42/MWh to $52/MWh in the 100
percent renewables case in recognition of the need for a more diverse mix of renewable resources.
Again,this higher price may be mitigated if large solar projects continue to be pursued in California.
As shown above, the base case 20-year levelized cost of renewable resources is comparable to the
20-year levelized cost of market purchases. The cost of solar projects has declined significantly over
the past few years. The $42/MWh projection is based on the cost of relatively new solar projects
that reflect the decreased costs,on a$/watt basis,of solar projects and the extension of the Federal
production tax credit. The $/watt is expected to continue to decrease in future years. As such, the
cost of the output of solar projects is expected to continue to decrease.
On a $/watt basis,the cost of smaller scale solar projects is greater than the cost of large scale solar
projects. The $65/MWh cost associated with local renewables reflects this trend. The advantage
of local renewable projects is lower transmission costs and less stress on the congested
transmission grid.
Portfolio 1: Meet Current RPS Requirements (Baseline Portfolio, similar to current SCE resource
mix)
In the first portfolio, LACCE will meet the State RPS requirements shown below:
• 2017-19: 25 percent
• 2020-23: 33 percent
• 2024-26: 40 percent
• 2027-29: 45 percent
• 2030- 50 percent
As shown above, due to the decrease in the cost of solar projects,the projected cost of renewables
is only slightly greater than the cost of market power and less than the cost of greenfield brown
resources (e.g. natural gas fired generation). Exhibit 19 shows the power supply portfolio used to
serve load in Portfolio 1.
Ordinance No.461
59
Exhibit 19
Portfolio 1: Meet RPS Requirements
500
450
400
350
300
2 250
m
200
150
100
50
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
•Market PPA •Brown Resources ■Renewables ■Local Renewables •Spot Market
The green bars increase each year along with California's RPS requirements. The costs associated
with this portfolio could be reduced if it was assumed that more power was purchased from market
PPAs instead of brown resources. The percent of non-renewable energy purchased via market
PPAs, as opposed to brown resources, is the same in each of the three portfolios.
Portfolio 2: Serve 50%of Retail Load with Renewables Starting on Day 1
In this portfolio, the 50 percent renewable energy purchase requirement in the RPS is effectively
moved up from 2030 to January 1, 2017. The amount of power purchased from the relatively
expensive ($65/MWh 20-year levelized cost) local renewables is held constant at 20 MW with a 33
percent capacity factor in each of the three portfolios. As shown below in Exhibit 20 the green bars
showing renewable energy purchases in 2017 through 2029 increased compared to those shown
above in Exhibit 19.
Ordinance No.461
60
Exhibit 20
Portfolio 2: Serve 50%of Retail Load with Renewables
500
450
400
350
300
250
2(X)
150
100
50
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036
■Market PPA •Brown Resources •Renewables •Local Renewables •Spot Market
The percentage of non-renewable energy purchased from the more expensive brown resources is
approximately the same as Portfolio 1. In all three portfolios, approximately 15 percent of non-
renewable energy is purchased from brown resources, which has a base case 20-year levelized cost
of$60/MWh. In all three portfolios, 85 percent of non-renewable energy is purchased at the lower
$41.5/MWh levelized cost associated with market PPA purchases.
Portfolio 3: Serve 100%of Retail Load with Renewables Starting on Day 1
In this portfolio retail loads are served entirely with renewable energy purchases. It is also assumed
that 50 MW of local renewable energy projects will be pursued in Phase 3. Exhibit 21 below shows
the resource mix used to serve load in Portfolio 3.
Ordinance No.461
61
Exhibit 21
Portfolio 3: Serve 100%of Retail Load with Renewables
500
450
400
350
300
2 250
m
200
150
100
50
11 11 111
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031. 2032 2033 2034 2035 2036
■Market PPA ■Brown Resources ■Renewables ■Local Renewables ■Spot Market
There is a small amount of market PPA and brown resource power included in Portfolio 3 due to
distribution and transmission system losses and balancing requirements. The renewable energy
requirements in the State's RPS are based on retail energy sales. To be consistent, it was assumed
that the 100 percent renewable energy target would only apply to retail energy sales. The same
concept applies to Portfolios 1 and 2. For example, renewable energy purchases in Portfolio 2 are
equal to 50 percent of projected retail energy sales in all years.
Non-renewable resources will be needed in Portfolio 3 to serve load during hours when renewable
resources are not capable of generating power (e.g. when the wind is not blowing or the sun is not
shining). Purchasing an amount of renewable generation that is equal to 100 percent of LACCE's
retail load will likely result in over-supply in on-peak hours when solar projects are generating
power and under-supply in off-peak hours when solar projects are not generating. As such, on-
peak energy may need to be exchanged for off-peak energy. The cost of exchanging or firming
some of the solar generation into off-peak blocks of energy is reflected in higher ancillary service
costs in Portfolio 3.
20-Year Levelized Portfolio Costs
The 20-year levelized costs have been calculated based on the base case assumptions detailed
above regarding resource costs and resource compositions under the three portfolios. Exhibit 22
shows a breakdown of power, ancillary service and scheduling costs associated with each portfolio.
Ordinance No.461
62
Exhibit 22
20-year Levelized Base Case Portfolio Costs($/MWh)
70 $66/M W h
65
60
55 $51/MWh $52/MWh
50
axe
45
t 40
2 35
v* 30
25
20
15
10
5
0
RPS 50%Green 100%Green
■Power ■Ancillary Services M Scheduling
As shown above in Portfolios 1 and 2, power costs are fairly similar across the three portfolios.
There is not a large variance in power costs in these two portfolios because the majority of power
is supplied by market PPA and renewable energy purchases in each portfolio. The projected costs
of renewable energy and market PPA purchases are very close. Exhibit 18 shows that at$42/MWh
the projected 20-year levelized cost of renewables is only$0.5/MWh greater than the projected 20-
year levelized cost of market PPA purchases at$41.5/MWh.
Total costs under Portfolio 3 are approximately$15/MWh greater than Portfolios 1 and 2. The costs
of renewables have been assumed to be $10/MWh greater in Portfolio 3 than in Portfolios 1 and 2
in recognition of the need for a more diverse mix of renewable resources. This translates into
greater power costs (the blue bar)for Portfolio 3.
Each portfolio assumes that 15 percent of non-renewable energy is purchased from brown, natural
gas-fired resources with a projected 20-year levelized cost of$66/MWh. However, since more non-
renewable energy is purchased in Portfolio 1 it has the highest percentage of brown resource
purchases. In Portfolio 1, 9 percent of power purchases are brown resource purchases, compared
to 8 percent in Portfolio 2 and 1 percent in Portfolio 3.
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LACCE Cost of Service
This section of the Plan describes the financial pro forma analysis and cost of service for LACCE. It
includes estimates of start-up costs, staffing and administrative costs, consultant costs, power
supply costs, and SCE charges. In addition, it provides an estimate of start-up working capital and
longer-term financial needs.
Cost of Service for LACCE Operations
The first category of the pro forma analysis is the cost of service for LACCE operations.To estimate
the overall costs associated with LACCE operations,the following components have been included:
■ Power Supply Costs
■ Non-Power Supply Costs
• Start-up costs
• LACCE staffing and administration costs
• Consulting Support
• SCE and regulatory charges
• Financing costs
■ Pass-Through Charges from SCE
• Transmission and distribution charges
• Power Cost Indifference Adjustment (PCIA) Charge
• Other non-bypassable charges
Once the costs of LACCE operations have been determined, the total costs can be used to develop
LACCE rates to be compared to SCE's projected rates.
Power Supply Costs
A key element of the cost of service analysis is the assumption that electricity will be procured under
a power purchase arrangement (PPA) for both renewable and non-renewable power until local
LACCE resources can be developed. Power supply must be obtained by LACCE's procurement
contractor prior to commencing operations. The products required from the third party
procurement are energy,capacity, renewable energy, load forecasting and scheduling coordination.
The calculated starting cost of electric power supply, including the cost of the scheduling
coordinator and all regulatory power requirements, is between $43 and $62 per MWh. This price
represents the price needed for a full requirements electricity contract. The variation in price is a
function of the desired level of renewable resources.
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Non-Power Supply Costs
While power supply costs make up the majority of costs associated with operating LACCE (roughly
80 percent),there are several additional cost components that must be considered in the pro forma
financial analysis. These additional non-power supply costs are noted below. This calculation
assumed LACCE non-power supply costs began accumulating in June of 2016.
Startup Activities and Costs
Monthly costs associated with LACCE start-up and phasing of customer enrollments include
expenditures for program staff/contract staff, associated infrastructure, contractor costs and fees
payable to SCE by LACCE. The estimated startup costs include capital expenditures and one-time
expenses as well as ongoing expenses that will be accrued before significant revenues from LACCE
operations are realized. These cost components are quantified in Exhibit 23 and Exhibit 24 below.
Exhibit 23
Monthly Start-Up Cost Summary
Pre-Start
June July Aug Sept Oct Nov Dec
Start-Up Costs
Infrastructure $0 $0 $45,000 $35,000 $25,000 $25,000 $25,000
Consultants $70,000 $100,000 $120,000 $120,000 $120,000 $130,000 $130,000
Staffing $0 $0 $45,000 $55,000 $55,000 $55,000 $55,000
Utility Trans.
Fee $0 $0 $0 $780 $0 $0 $2,938
Total Start-Up $70,000 $100,000 $210,000 $210,780 $200,000 $210,000 $212,938
Exhibit 24
Start-Up Costs Summarized by Phase
Phase 1 Phase 2
Total Pre-Start Costs 2017 2018
Start-Up Costs
Infrastructure $155,000 $160,000 $230,000
Consultants $790,000 $715,000 $715,000
Staffing $265,000 $380,000 $1,215,000
Utility Trans. Fee $3,718 $1,132,892 $230,000
Total Start-Up $1,213,718 $2,387,892 $2,390,000
Other costs related to starting up LACCE's program will be the responsibility of LACCE's contractors.
These include capital requirements paid by others, customer information system costs, electronic
data exchange system costs, call center costs, and billing administration/settlements systems costs.
The costs payable by LACCE are contained in Exhibit 24.
Estimated Staffing Costs
Staffing is a key component of the start-up. Staff will be added incrementally to match workloads
involved in forming LACCE, managing contracts, and initiating customer outreach/marketing during
the pre-operations period.
Exhibit 25 provides the estimated staffing budgets for the startup period (Phase 1 and Phase 2 of
LACCE implementation). Staffing budgets include direct salaries and benefits. For start-up, it is
Ordinance No.461
65
anticipated that LACCE will employ one assistant Executive Director and one manager of policy and
regulatory affairs. The remaining functions will be performed by consultants. Exhibit 25 details the
anticipated staffing of LACCE.
Exhibit 25
Staffing Plan
Number of Staff Pre Start-Up 2017 2018
Executive Director 0 1 1
Assistant Executive Director 1 1 1
Legal,Policy&Regulatory Manager 1 1 1
Regulatory Analyst 0 1 1
Administrative Assistant 0 1 1
Finance&Rates Manager 0 1 1
Rates Analyst 0 1 1
Accounting&Billing Analyst 0 1 1
Human Resources Manager 0 1 1
HR Specialist 0 1 1
Sales&Marketing Manager 0 1 1
Energy Efficiency Program Manager 0 0 1
Account Representatives 0 0 1
Communication Specialists 0 0 1
IT Manager 0 1 1
IT Specialist 0 0 1
Total Number of Employees 2 12 17
Total Staffing Costs $45,000* $1,595,000 $3,396,600
*Represents only partial year.
Based on this staffing plan, LACCE will initially employ 2 staff members. Once LACCE has expanded
its service area to the unincorporated County and operated for one year, it is anticipated that
staffing will increase to approximately 17 employees. These positions to be hired by LACCE over
the first two years are described below:
Executive Director
The Executive Director will be responsible for overseeing LACCE operation and ensuring that the
vision of the JPA Board is followed. The Executive Director will ultimately be responsible for all
LACCE programs, finances and communication programs plus be accountable to the Board.
Assistant Executive Director
The Assistant Executive Director will oversee the day to day operation of LACCE. In particular, this
staff position will work closely with outside consultants, and oversee hedging and power
procurement, resource portfolio strategy, CAISO settlements and other financial planning and rate
setting analysis. Behind the meter LACCE programs will also be coordinated through this position.
Policy and Regulatory Manager
The Policy and Regulatory Manager will oversee the legal and regulatory functions of LACCE. This
position will work closely with the CPUC and State/Federal legislators. LACCE will require ongoing
regulatory representation to file resource plans, resource adequacy compliance, compliance with
Ordinance No.461
66
California RPS,and overall representation on issues that will impact LACCE and its customers. LACCE
will maintain an active role at the CPUC, CEC, FERC and the California legislature.
Finance and Rates Manager
The Finance and Rates Manager oversees LACCE's budgets and accounting functions. In addition,
this person will develop annual budgets, rates and credit policies for approval by the Board.
Managing the overall financial aspects of LACCE is expected to be a significant work activity.
Sales and Marketing Manager
The Sales and Marketing Manager is responsible for the enrollment and notification of new
customers. In addition, this staff person will market LACCE, and provide on-going communication
with LACCE's communities and customers. A significant amount of customer service and key
account representation will be necessary in addition to regular marketing services. This position
will be the point person for the outsourced data management and customer service consultants.
Administrative Assistance
The staffing plan assumes a full-time administrative assistance will be added during the pilot phase
to provide administrative assistance to management.
Future Staff
As additional customers join LACCE, duties can be shifted from third-party consultants to in-house
staff if internal staffing is more cost effective.
Estimated Infrastructure Costs
Infrastructure or overhead needed to support the organization includes computers and other
equipment, office furnishings, office space and utilities.These expenses are estimated at $155,000
during program pre-startup. Office space and utilities are ongoing monthly expenses that will begin
to accrue before revenues from program operations commence and are therefore assumed to be
financed as shown in Exhibit 26 and Exhibit 27.
Exhibit 26
Monthly Estimated Infrastructure Costs
Pre-Start
June July Aug Sept Oct Nov Dec
Infrastructure Costs
Computers $0 $0 $10,000 $5,000 $0 $0 $0
Furnishings $0 $0 $10,000 $5,000 $0 . $0 $0
Office Space $0 $0 $15,000 $15,000 _ $15,000 $15,000 $15,000
Utilities/Other
Office Supplies $0 $0 $10,000 $10,000 $10,000 $10,000 $10,000
Total Start-Up $0 $0 $45,000 $35,000 $25,000 $25,000 $25,000
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Exhibit 27
Estimated Infrastructure Cost by Phase
Phase 1 Phase 2
Total Pre-Start Costs 2017 2018
Infrastructure Costs
Computers $15,000 $5,000 $40,000
Furnishings $15,000 $5,000 $40,000
Office Space $75,000 $90,000 $90,000
Utilities/Other Office Supplies $50,000 $60,000 $60,000
Total Infrastructure Costs $155,000 $160,000 $230,000
It is estimated that the per employee start-up cost is approximately $10,000. This expense covers
computer and furniture needs. An additional annual expense of $180,000 for office space, and
approximately$120,000 per year in office supplies and utilities costs is expected.
Utility Implementation and Transaction Charges
The estimated costs payable to SCE for services related to LACCE start-up include costs associated
with initiating service with SCE, processing of customer opt-out notices, customer enrollment, post
enrollment opt-out processing, and billing fees. These distribution utilities fees are explicitly stated
in the relevant SCE tariffs.
Customers who establish service with LACCE will be automatically enrolled in the program and have
sixty days from the date of enrollment to customer opt-out of the program. Such customers will be
provided with two opt-out notices within this sixty-day post enrollment period. The first notice will
be mailed to customers approximately sixty days prior to the date of automatic enrollment. A
second notice will be sent approximately thirty days later. As required by CPUC regulations, LACCE
will use SCE's opt-out processing service. Following automatic enrollment, two additional opt-out
notices will be provided within the sixty-day period following customer enrollment. It is estimated
that the charges for the opt-out notices will be approximately$10,000 for 2016 and $3.1 million for
2017, as shown in Exhibit 28 and Exhibit 29.
Exhibit 28
Monthly Utility Transaction Fees
Pre-Start
June July Aug Sept Oct Nov Dec
Enrollment Charges $0 $0 $780 $0 $0 $2,938 $6,203
Ongoing Charges $0 $0 $0 $0 $0 $0 $0
Total SCE
Transaction Fee $0 $0 $780 $0 $0 $2,938 $6,203
Exhibit 29
Utility Transaction Fees by Phase
Phase 1 Phase 2
Total Pre-Start Costs 2017 2018
Enrollment Charges $9,921 $1,128,588 $1,212,268
Ongoing Charges 0 4,305 779,791
Total SCE Transaction Fees $9,921 $1,132,892 $1,992,059
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Estimates of Third Party Consultant Costs
Contractor costs include outside assistance for advertising, legal services, resource and financial
planning, implementation support, customer enrollment, customer service, and payment
processing/accounts receivable and verification. The latter three will be provided by LACCE's
customer account services provider, and these preliminary estimates will be refined as the services
and costs provided by the selected contractor are negotiated. Exhibit 30 and Exhibit 31 show the
estimated contractor costs during the startup period.
Exhibit 30
Monthly Estimated Consultant Costs
Pre-Start
June July Aug Sept Oct Nov Dec
Legal/Regulatory $20,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000
Communication $0 $0 $0 $0 $0 $10,000 $10,000
Data Management $0 $0 $20,000 $20,000 $20,000 $20,000 $20,000
Financial Consulting $50,000 $50,000 $50,000 $50,000 $50,000 $50,000 $50,000
Total Consultant
costs $70,000 $100,000 $120,000 $120,000 $120,000 $130,000 $130,000
Exhibit 31
Estimated Consultant Costs by Phase
Phase 1 Phase 2
Total Pre-Start Costs 2017 2018
Legal/Regulatory $320,000 $250,000 $250,000
Communication $20,000 $200,000 $200,000
Data Management $100,000 $12,960 $2,377,248
Financial Consulting $350,000 $265,000 $265,000
Total Consultant Costs $790,000 $727,960 $3,092,248
The estimate for each of the services is based on costs experienced by other CCEs.
Cash Flow Analysis and Working Capital
This cash flow analysis estimates the level of working capital that will be required until full operation
of LACCE is achieved. For the purposes of this analysis, it is assumed that LACCE pre-operations
begin in June 2016 and continue through the end of 2016. In general, the components of the cash
flow analysis can be summarized into two distinct categories: (1) Cost of LACCE operations, and (2)
Revenues from LACCE operations. The cash flow analysis identifies and provides monthly estimates
for each of these two categories. A key aspect of the cash flow analysis is to focus primarily on the
monthly costs and revenues associated with LACCE and specifically account for the transition or
"Phase-In" of LACCE customers. The cash flow analysis assumes the phase-In schedule for LACCE
as described previously.
The cash flow analysis also provides estimates for revenues generated from LACCE operations or
from electricity sales to customers. In determining the level of revenues, the cash flow analysis
assumes the customer phase-in schedule noted above, and assumes that LACCE provides a discount
of 4.0 percent from the existing rates for each customer class, where pre-operations run from June
1, 2016 to December 31, 2016. Thereafter, Phase 1 starts in January 2017 and Phase 2 starts in July
2017.
Ordinance No.461
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The results of the cash flow analysis provide an estimate of the level of working capital required for
LACCE to move through the pre-operations period. This estimated level of working capital is
determined by examining the monthly cumulative net cash flows (revenues minus cost of
operations) based on assumptions for payment of costs by LACCE, along with an assumption for
when customer payments will be received. The cash flow analysis assumes that customers will
make payments within 60 days of the service month, and that LACCE will make payments to
suppliers within 30 days of the service month. This analysis is somewhat conservative because
customer payments begin to come in soon after the bill is issued, and most are received before the
due date.At the same time, some customer payments are received well after the due date.The 30-
day net lag is a conservative assumption for cash flow purposes.
For purposes of determining working capital requirements related to power purchases, LACCE will
be responsible for providing the working capital needed to support electricity procurement unless
the electricity provider can provide the working capital as part of the contract services. In addition,
LACCE will be obligated to meet working capital requirements related to program management.
For this Plan, it is assumed that this working capital requirement is included in the short term
financing associated with start-up funding.
A summary of working capital needs is presented below on Exhibit 32.
Exhibit 32
Working Capital Needs
2016 2017
Working Capital $6,500,000 $42,000,000
Total Financing Requirements
The start-up of the LACCE program will require a significant amount of capital for three major
functions: (1) staffing and contractor costs; (2) program initiation; and (3) working capital. Each of
these anticipated requirements is discussed below.
Staffing costs for the pre-implementation period (June 2016 through December 2016) are
estimated to be approximately$265,000. Contractor costs for the same time period are estimated
to be approximately$790,000.These costs include: advertising/communications, consulting, legal,
and data management.
LACCE initiation costs include the infrastructure that LACCE will require (office space, utilities,
computers) as well as the distribution utility fees for initiating LACCE. Infrastructure costs are
estimated to be approximately $155,000 and the distribution utility fees are estimated to be
approximately$1,140,000.
The Public Utilities Code requires demonstration of insurance or posting of a bond sufficient to
cover reentry fees imposed on customers that are involuntarily returned to SCE service under
certain circumstances. In addition, SCE requires a bond equivalent to two months of transaction
fees.
Ordinance No.461
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During the start-up and pilot periods, the total financing requirements are estimated to be
approximately $10 million, increasing to approximately $40 million following enrollment of
unincorporated County customers. The first$10 million is needed in early summer of 2016.
Financing Plan
The initial start-up funding will be provided via short-term financing. LACCE will recover the
principal and interest costs associated with the start-up funding via subsequent retail rates. It is
anticipated that the start-up costs will be fully recovered within the first two years of LACCE
operations.
The anticipated start-up and working capital requirements for LACCE through Phase 1 are
approximately $10 million. Once the LACCE program is up and running, these costs would be
recovered through retail rates. Actual recovery of these costs will be dependent on third-party
electricity purchase prices and decisions regarding initial rates for Phase 1 customers.
Additional financing will be needed at the beginning of Phase 2. Depending on market conditions
and payment terms established with the third-party suppliers, the loan may need to be increased
to approximately $42 million for the start of Phase 2. This number will be refined as the LACCE
program becomes operational, and bids are received from power providers.
Appendix B contains a preliminary discussion from Public Financial Management, Inc. (PFM) on the
options available to LACCE for funding the first two phases of LACCE operations. Based on this
information, the Plan's financial analysis assumes that LACCE can obtain a loan for the first $10
million with a term of 2 years at a rate of 5.5 percent. The second loan for$42 million is assumed
for a 20-year term at 5.5 percent.
Ordinance No.461
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Products, Services, Rates Comparison and
Environmental/Economic Impacts
This section of the Plan provides a comparison of service and rates between SCE and LACCE. Rates
are evaluated based on total LACCE electric total bundled rates as compared to SCE's total bundled
rates. Total bundled electric rates include the rates charged by LACCE, including non-bypassable
charges, plus SCE's delivery charges. This section also includes the environmental impacts based
on the reduction in Green House Gases(GHG), and the economic development impact on local jobs
and overall economic activity created by LACCE programs.
Rates Paid by SCE Bundled Customers
The average customer weighted SCE rates have been calculated based on current rate schedules
and LACCE's projected customer mix. SCE's current 2016 rates and surcharges have been applied
to customer load data aggregated by major rate schedules to form the basis for the SCE rate
forecast.
The average SCE delivery rate, which is paid by both SCE bundled customers and LACCE bundled
customers, has been calculated based on the forecasted customer mix for LACCE. For future years,
the SCE rate forecast assumes the delivery costs will increase by 2 percent per year, a conservative
assumption given the history of SCE rate increases.
Similarly, the current average power supply rate component for SCE bundled customers has been
calculated based on the estimated LACCE customer mix. The SCE power supply rate component has
been forecast to increase based on SCE's most recent filings and incorporating the increased RPS
requirement mandated by SB 350. In the 2015/2016 Energy Resource Recovery Account (ERRA)
filing, SCE reduced overall power supply rates due to lower than anticipated fuel and purchase
power,over collection in balancing accounts,and adjustment of GHG costs and allowance revenues.
Some of these adjustments are one time only and of short duration while others are due to the
current energy market in California. For 2017, SCE rates have been normalized to remove the one-
time impact of over collection of balancing accounts and other onetime adjustments. Finally, the
SCE power supply rates have been projected to increase based on the renewable and non-
renewable market price forecast, regulatory requirement for RPS, storage requirement(s) and
resource adequacy objectives.
Rates Paid by LACCE Customers
It is anticipated that LACCE's rate designs will initially mirror the structure of SCE's rates so that
similar rates can be provided to LACCE's customers. In determining the level of LACCE rates, the
financial analysis assumes the customer phase-in schedule noted above and that the
implementation phase costs are financed via a start-up loan.
Ordinance No.461
72
In addition to paying LACCE's power supply rate, LACCE customers will pay the SCE delivery rate and
several non-bypassable charges. The calculation of the delivery rate is described earlier. The non-
bypassable charges that are payable to SCE by LACCE customers include:
• Power Cost Indifference Adjustment (PCIA)
• Department of Water Resources Bond Charge (DWRBC)
• Competition Transition Charge (CTC)
• Generation Municipal Surcharge (or Franchise Charge)
The DWRBC is the charge to recover the interest and principle of the California Department of
Water and Resources (DWR) bonds. The CTC is the ongoing charge which recovers the above
market costs of utility generation. The PCIA is a charge that is designed to keep bundled customers
indifferent when other customers leave bundled service. The PCIA is calculated annually by
subtracting the market price of wholesale power from the incumbent utility's average cost of power
supply based on a methodology determined by the CPUC.4
Exhibit 33 provides the historic values of the PCIA, CTC and DWRBC for the residential customer
class (domestic schedule). It is important to note that the non-bypassable charges differ by the
vintage of a CCA. The vintage of the CCA depends on when the CCA provides a binding notice of
intent to SCE.
Exhibit 33
SCE Historic Domestic Non-Bypassable Charges
0.035
0 03
0 025
0 02
0.015
001
0 005 -..�,
0
2009 2010 2011 2012 2013 • 201',
-0 005
Year
—2009 Vintage—2010 Vintage—2011 Vintage—2012 Vintage—2013 Vintage
—2014 Vintage—2015 Vintage—CTC —DWRBC
Note that CARE and medical base line customers do not pay the DWRBC or PCIA charges.
For this Plan, it is assumed in the base case that the PCIA charges are based on the differential
between SCE's generation cost and market prices. If the difference between SCE's power costs and
4 See D.-6-07-030 as modified by D. 11-12-018.
Ordinance No.461
73
market prices declines, then the PCIA will decline. The PCIA increases if the difference between
market price and SCE generation costs increases. For this Plan, the PCIA is forecast to increase
initially due to the end of offsetting credits that expire in 2018. Post-2018, the PCIA is expected to
grow based on the inverse of the market price growth rate. As market prices increase,SCE's surplus
resources become more cost effective and the PCIA therefore decreases.
Rate Impacts
Based on LACCE's projected power supply costs/operating costs and SCE's power supply/delivery
costs, forecasts of LACCE and SCE total rates have been developed. These rates are illustrated
below on Exhibit 34.
Exhibit 34
Average Total Retail Rate Comparison
�z1
0 19
018
� I
'" 017
0.16
0 15
0.14
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
-SCE Average LACCE Rate -LACCE Average Rate 50%Green
-Historic SCE System Average Rate -LACCE Average Rate 100%Green
-LACCE Average Rate RPS
As can be seen above, LACCE RPS residential rate with an equal amount of renewable power (28
percent)to what SCE currently offers is .9C/kWh or 5.4 percent lower than SCE's 2017 rates. LACCE
residential rate with 50 percent renewable power(compared to SCE's 28 percent) is .7C/kWh or 4.1
percent lower than SCE's rates for roughly twice the amount of green renewable power. LACCE
residential rate with 100 percent green power (compared to SCE's 28 percent) is 1.1C/kWh or 6.3
percent higher, but this additional amount comes with almost four times more renewable power
than the comparable SCE rate. These rate calculations assume all bill savings associated with
forming LACCE will be refunded to the residences and businesses within the County. Based upon
final LACCE policy direction, some of these savings could be retained by LACCE to build up financial
reserves and/or build more local renewable energy projects.
As an alternative to its standard rates with 28 percent renewable power,SCE also offers rates which
feature 50 percent and 100 percent renewable power. For the residential customers,SCE estimates
energy costs to be 3.5 cents per kWh higher for each kWh served on the green rate. The LACCE
Ordinance No.461
74
rates for 50 percent and 100 percent renewable power for residential customers are therefore
estimated at 12-13 percent lower.
Based on these assumed LACCE discounts off the comparable SCE rate, Exhibit 35 provides a
comparison of the indicative bundled rates for LACCE's products compared to the current SCE rate.
Exhibit 35
Indicative Rate Comparison($/kWh)
Rate Class SCE Bundled LACCE RPS Bundled LACCE 50%Green LACCE 100%Green
Rate* Rate Bundled Rate Bundled Rate
Residential 17.1 16.2 16.4 18.2
GS-1 16.6 15.7 15.9 17.7
GS-2 15.8 15.0 15.2 16.9
G5-3 14.5 13.8 13.9 15.5
PA-2 12.6 12.0 12.1 13.4
PA-3 10.4 9.9 10.0 11.1
TOU-8 Secondary 13.1 12.4 12.6 14.0
TOU-8 Primary 11.7 11.1 11.2 12.5
TOU-8 Substation 7.5 7.1 7.2 8.0
Total LACCE Rate Savings
5.4%
4.1% (6.3%)
(Increases)
*SCE bundled average rate based on Table 3 in Advice 3319-E-A.
A financial proforma in support of these rates can be referenced in Appendix C.
Local Resources/Behind the Meter LACCE Programs
LACCE should plan to establish a Net Energy Metering ("NEM") program for qualified customers in
their service territory to encourage Distributed Energy Resources (DER). In addition, LACCE will
work with State agencies and SCE to promote deployment of DER within LACCE's service territory,
with the goal of maximizing use of the available incentives that are funded through current utility
distribution rates and public goods surcharges.
LACCE should also establish a program which offers a combination of retail tariffs, rebates,
incentives and other bundled offerings intended to increase customer participation in demand-side
programs including: renewable distributed generation, energy storage, energy efficiency, demand
response, electric vehicle charging, and other clean energy benefits defined as Distributed Energy
Resources (DER). LACCE will work with State agencies and SCE to promote deployment of DER5 in
specific and targeted locations throughout SCE's distribution grid in order to help support efficient
grid operations and maintenance as part of development of the future "smart grid.".
Additionally, LACCE will pursue energy efficiency programs at a faster pace than SCE. Below are
ongoing activities undertaken by the SoCaIREN under two current proceedings at the CPUC which
are leading to a transformation of the energy industry.
Under the CPUC's current Energy Efficiency Proceeding (R. 13-11-005), the SoCaIREN has already
been established as an independent administrator of energy efficiency funding provided from
Southern California Edison and Southern California Gas Company ratepayers. The current
proceeding seeks to establish energy efficiency programs under a "Rolling Portfolio" funding cycle
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which could provide stable, predictable program funding for up to 10 years. The "Rolling Portfolio"
concept will allow energy efficiency program administrators, like the SoCaIREN, to conduct more
strategic planning, development and implementation of programs.
Under the CPUC's current Distribution Resource Plans (R.14-08-013), and Distributed Energy
Resources (R. 14-10-003) Proceedings, the SoCaIREN is a proceeding participant seeking to help
establish resource programs which are comprehensive (i.e., include all demand side management
resources such as energy efficiency, storage, demand reduction, distributed generation) and which
are compensated for multiple benefits that they produce (energy efficiency, real-time grid
operations benefits, reduced grid operations and maintenance expenses, and greenhouse gas
reductions). Each of these proceedings examine different aspects of creating, integrating and
funding distributed energy resources.
CCEs, as entities that can provide wholesale power and design retail rates without lengthy and
expensive regulatory proceedings, and as entities that can design and implement other end-user
programs using wholesale power or other revenues, are uniquely positioned to be valued partners
of investor-owned utilities who would retain their role as distribution grid operators. CCEs program
and rate flexibilities can perfectly complement utilities efforts to maximize grid operations and
flexibility in a world where behind the meter (and ahead of the meter) distributed generation,
energy storage,thermal storage, electric vehicle charging, demand reduction and energy efficiency
will increase dramatically. CCEs can partner with utility grid operators in aggregating and financing
locational-specific distributed resources in grid areas of specific needs as well in assisting IOUs in
investing in these distributed resources.
The SoCaIREN is already funded and operational, and is an active participant in these new
proceedings. This is advantageous in that any new CCE would typically have to apply for energy
efficiency or other CPUC funding under regulated proceedings.
Impact of Resource Plan on Greenhouse Gas (GHG) Emissions
The amount of renewable power in SCE's power supply portfolio is 28 percents and will rise to 33
percent by 2020. LACCE is committed to reductions in greenhouse gas emissions. Based on the
power supply strategy described previously, GHG emission reductions resulting from the formation
of LACCE are estimated to range from 289,080 to 505,890 tons CO2e per year by 2019 assuming a
50 percent RPS target is achieved. The baseline for comparison is the projected resource mix used
by SCE in the same time period. Exhibit 36 details these reductions.
http://www.cpuc.ca.gov/RPS_Homepage/
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Exhibit 36
Baseline Comparison of GHG Reduction by LACCE
2017 2018 2019
Forecast Renewables(50% Renewables) 1,438,275 1,459,854 1,459,854
LACCE (MWH)—Phase 2
LACCE RPS(MWH)—Phase 2 730,029 737,154 737,154
Additional Green Power 708,246 722,700 722,700
CO2 reduction—Low(Metric Tons of CO2e) 283,298 289,080 289,080
CO2 reduction—High(Metric tons of CO2e) 495,772 505,890 505,890
These reductions in GHG emissions associated with LACCE operations are significant. Assuming only
Phase 2 loads(all unincorporated County loads) are being met by LACCE, CO2e emissions associated
with in-County electricity use will be reduced by 1-2 percent. At full Phase 3 build-out, CO2
emissions associated with in-County electricity use will be reduced roughly 12-25 percent by LACCE
operations.
Economic Development
The analyses contained in this Plan of forming LACCE has focused only on the direct effects of this
formation. However, in addition to direct effects, indirect microeconomic effects are also
encountered.
The indirect effects of creating LACCE include the effects of increased commerce and improved
environmental and health conditions. Within this Plan, an Input/Output (10) analysis is undertaken
to analyze these indirect effects. The 10 model turns on the assumption that forming LACCE will
lead to lower energy rates for their customers. Three types of impacts are analyzed in the 10 model.
These are described below.
Local Investment — LACCE will likely choose to implement programs to incentivize investments in
local distributed energy resources (DER). Participants in LACCE may pursue local clean DER. These
resources can be behind the meter or community projects where several customers participate in
a centrally located project. This demand for local resources will lead to an increase in the
manufacturing and installation of DER and lead to an increase in employment the manufacturing
and construction sectors.
Increased Disposable Income — Establishing LACCE will lead to reduced customer rates for energy,
more disposable income for individuals and greater revenues for businesses. These cost savings
would then lead to more investment by individuals and businesses for personal or business
purposes. This increase in spending will then lead to increased employment for multiple sectors
such as retail, construction, and manufacturing.
Environmental and Health Impacts — With the creation of LACCE, other non-commerce indirect
effects will occur. These may be largely environmental such as improved air quality or improved
human health due to LACCE adopting mainly renewable energy sources versus continuing use of
traditional energy sources. This resource strategy significantly reduces GHG emissions compared
with SCE's current resource mix. While the change in GHG emissions is not modeled directly in
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economic development models used in this Plan, the reduction of these GHGs may be captured in
indirect effects projected by the models.
Input-Output Modeling (10 modeling)
10 modeling is a quantitative analysis representing relationships (dependence) between industries
in an economy. 10 models are based on the implicit assumption that each basic sector has a
multiplier,or ripple effect,on the wider economy because each sector purchases goods and services
to support that sector. 10 modeling estimates the inter-industry transactions and uses those
transactions to estimate the economic impacts of any change to the economy.
The 10 model used in the Plan, IMPLAN, displays the economic impacts of changes in rates into four
categories:employment, labor income,value added,and output. Employment is the number of jobs
gained or lost. Labor income involves the increase in salaries and wages for current and newly
gained or lost employees. Value added, similar to Gross Domestic Product (GDP), is the payment
to labor and capital used in production of a particular industry.
10 models are made up of matrices of multipliers between each industry present in an economy.
Each column shows how an industry is dependent on other industries for both its inputs to
production and outputs. The tables of multipliers can be used to estimate the effects in changes in
spending for various industries, household consumption, or labor income. Both positive and
negative impacts can be measured using 10 modeling. 10 modeling produces results broken down
into several categories. Each of these is described below:
■ Direct Effects — Increased purchases of inputs used to produce final goods and services
purchased by residents. Direct effects are the input values in an 10 model, or first round effects.
■ Indirect Effects — Value of inputs used by firms affected by direct effects (inputs). Economic
activity that supports direct effects.
■ Induced Effects—Results of Direct and Indirect effects(calculated using multipliers). Represents
economic activity from household spending.
■ Total Effects—Sum of Direct, Indirect, and Induced effects.
■ Total Output—Value of all goods and services produced by industries.
■ Value Added—Total Output less value of inputs, or the Net Benefit/Impact to an economy.
■ Employment — Number of additional/reduced full time employment resulting from direct
effects.
This study uses value added and employment figures to represent the total additional economic
impact for each Project Alternative. IMPLAN has been used in this Plan to gauge the impacts on the
County of retail rate reductions associated with forming LACCE. These impacts are discussed in
detail below.
Increase in Disposal Income Associated with Rate Reduction Impacts
Exhibit 37 shows the effects$20 million in rate savings will have on the County's economy. The$20
million rate savings represents the minimum bill savings per year achievable by LACCE once Phase
3 operations begin. Direct effects from reduced rates are expected to add 98 jobs. Indirect effects
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are expected to add about 10 jobs. The induced effects of the project create approximately 211
jobs in the County with over $9.6 million in labor income. It is also projected that the total value
added will be approximately $15.9 million and output close to $24.2 million. Exhibit 37 details the
macroeconomics on the County of the anticipated LACCE customer bill reductions.
Exhibit 37
$20 Million Rate Savings Effects on County Economy
Impact Type Employment Labor Income Total Value Added Output
Direct Effect 98.3 $3,674,939 $5,376,863 $7,099,612
Indirect Effect 10.4 $608,838 $1,057,593 $1,677,591
Induced Effect 102.1 $5,319,262 $9,472,599 $15,391,851
Total Effect 210.7 $9,603,040 $15,907,056 $24,169,054
These savings are based on the economic construct that households will spend some share of the
increased disposable income on more goods and services. This increased spending on goods and
services will then lead to producers either increasing the wages of their current employees or hiring
additional employees to handle the increased demand.This in turn will give the employees a larger
disposable income which they spend on goods and services and thus repeating the cycle of
increased demand. Again, these macroeconomic impacts shown on Exhibit 37 could be 6-7 times
greater at Phase 3 build-out.
DER Development Impacts
The economic impacts of DER development are estimated using the Jobs and Economic
Development Impact(JEDI) model. JEDI estimates the effects of DER development on construction
industries and the local economy. JEDI was initially developed by the National Renewable Energy
Laboratory to demonstrate the economic benefits associated with constructing and operating wind
and photovoltaic systems in the United States. JEDI has since been expanded to analyze similar
economic impacts for various energy sources such as biofuels, coal, concentrating solar power,
geothermal, marine and hydrokinetic power, and natural gas. A primary goal of JEDI is that it is
being used as a tool for system developers, renewable energy advocates, government officials,
decision makers, and others to easily identify the local economic impacts associated with
constructing and operating these systems on the economy as a whole, whether through direct and
indirect effects.
Users input general information about a particular energy project, such as the project location, the
type of system being installed, nameplate capacity, annual operations and maintenance costs, and
others. JEDI has default but modifiable data regarding various aspects of each energy system type,
such as equipment costs, tax parameters, and labor costs. JEDI then uses the input general
information and the data, default or modified, to run calculations on the types of economic effects
produced by the proposed project.This model can output projected direct job creation by industry,
indirect job and business increases due to the project, projected operation costs, and more.
In order for JEDI to provide information, it must be populated with detailed data for the assumed
DER project. Projected system data,type of solar cell, nameplate capacity(kW), and the number of
systems. As an example of the macroeconomic activity caused by local DER deployment, this Plan
assumes the installation of a 50 crystalline silicon, fixed mount solar systems with nameplate
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capacities of 1 MW each for a total capacity of 50 MW. It is anticipated that LACCE will ultimately
install a number of larger local solar projects such as the one described above. Exhibit 38 describes
the macroeconomic impacts of constructing only one of these local solar projects.
Exhibit 38
Projected Solar Systems Impacts on County's Economy
Description Jobs Earnings,$000 Output(GDP),$000
During Construction and Installation Period •
*Project Development and Onsite Labor
Impacts
Construction and Installation Labor 342.5 $22,182
Construction and Installation
Related Services 374.3 $20,007
Subtotal 716.8 $42,189 $67,620
*Module and Supply Chain Impacts
Manufacturing Impacts 0.0 $0 $0
Trade(Wholesale and Retail) 79.4 $4,425 $12,887
Finance, Insurance and Real Estate 0.0 $0 $0
Professional Services 53.9 $2,326 $6,908
Other Services 141.4 $15,048 $42,364
Other Sectors 317.1 $10,656 $19,428
Subtotal 591.7 $32,455 $81,587
Induced Impacts 326.7 $13,067 $39,092
Total Impacts 1,635.3 $87,710 $188,298
During Operating Years
*Onsite Labor Impacts
PV Project Labor Only 9.2 $555 $555
*Local Revenue and Supply Chain Impacts 2.7 $145 $458
*Induced Impacts 1.9 $74 $221
Total Impacts 13.8 $774 $1,235
Exhibit 38 shows the construction and ongoing effects of building 50, 1 MW solar power systems.
It is projected that roughly 1,635 jobs will be created during construction and installation. Of this
total, about 719 jobs will be directly involved in construction and installation while roughly 592 jobs
will be indirectly involved with the building of the project. Induced impacts of the construction and
installation will create approximately 327 jobs. These induced effects may include anything from
increased employment in restaurants, retail,education,and others. Overall, the building of this one
solar project is projected to create $87 million in earnings and $188 million in output (GDP) in the
local economy along with 1,636 jobs during construction and 14 full-time jobs ongoing. LACCE will
need 2,000 — 3,000 MW of solar power plants at Phase 3 build-out so the potential employment
impact on the County could be very significant.
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Sensitivity Analysis
The aforementioned economic analysis provides the base case analysis of forming LACCE. This base
case is predicated on numerous assumptions and estimates that influence the overall results. This
section of the Plan will provide the range of impacts that could result from changes in the most
significant variables. In addition,this section will address risks that cannot be quantified, but should
be addressed and mitigated to the maximum amount possible. Each key assumption is discussed, a
band of uncertainty is established and LACCE's rate impacts associated with factoring in this
uncertainty is developed for each key variable.
Since resource costs are based on forecast natural gas, wholesale market and renewable market
prices, it is prudent to look at the sensitivity of the 20-year levelized cost calculation to fluctuations
in these projections. Exhibit 39 below shows a summary of low, base, and high resource costs.
Exhibit 39
Low,Base and High 20-year Levelized Resource Costs($/MWh)
Portfolio 1 and 2 Portfolio 3 Local
Case Market PPA Renewables Renewables Brown Resources Renewables
Low Case 25.0 32 40 45 45
Base Case 41.5 42 52 60 65
High Case 70.0 62 76 80 85
The 20-year levelized costs of each portfolio has been calculated using the range of resource costs
shown above. The base case costs are depicted by the black dots in Exhibit 40.
Exhibit 40
Sensitivity of Portfolio 20-year Levelized Costs
100
90
80
70 •
60
2 50 • •
40
30
20
10
0
RPS 50%Green 100%Green
Portfolio 3, which relies on renewable energy purchases to serve all retail loads, has the highest
projected costs that range from a low of$54/MWh to a high of$90/MWh. The low case for Portfolio
3 ($54/MWh) is greater than the base case for both Portfolios 2 and 3. The likelihood of solar costs
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increasing to the point that 20-year levelized costs are near $62/MWh seems unlikely. All signs
point to decreases in solar equipment costs on a $/watt basis. There have been significant
decreases in solar costs over the past few years. Given the financial incentives targeted at the solar
industry as well as the continuing advances in technology, it seems very unlikely that solar costs will
increase over the next 10 to 20 years.
The potential for market PPA prices to increase to the high case of $70/MWh has a much higher
likelihood. Wholesale market prices are dependent on many factors the most notable of which are
natural gas prices. Natural gas prices are at historic lows and wholesale market prices have
followed. However, natural gas prices are subject to variety of local, national and international
forces that could drastically alter the current market place. For one, increased regulation of the
natural gas industry with respect to the deployment of fracking technology could cause decreases
in natural gas supplies and commensurate increases in natural gas prices. If natural gas prices
increased, it is highly likely that electric wholesale market prices would also increase.
When evaluating risks, it is important to note that power supply costs are approximately 79 percent
of the total CCE costs, SCE non-bypassable charges account for 13 percent and CCE operating costs
account for 8 percent of total CCE revenue requirement.
Loads and Customer Participation Rates
The Plan bases the 20-year load forecasts on expected load growth, load profiles and participation
rates. In order to evaluate the potential impact of varying loads, low, medium, and high load
forecasts have been developed for the sensitivity analysis. SCE made available load shape profiles
by customer class for the entire SCE service area. These load profiles were applied to all customer
loads despite the varying climate zones within the County.
Another assumption that can impact the costs of LACCE are the customer participation rates. This
Plan uses a conservative participation rate as the base case. A higher participation rate will increase
energy sales relative to the base case and decrease the fixed costs paid by each customer. On the
other hand, a reduced participation rate will increase the fixed costs to LACCE participants.
Sensitivity to changes in projected loads has been tested for the high and low load forecast
scenarios. For the sensitivity analysis,the high case assumes an additional 10 percent participation
rate, while the low case assumes the participation rate is reduced by 50 percent. The low case
assumes a 0 percent growth in energy and customers after 2017, while the high scenario assumes
a 5 percent growth in energy and customers.
SCE Rates and Surcharges
The base case forecast of SCE rates assumes delivery rates increase at 2 percent per year and
generation rates increase approximately 2.0 percent based on the projected market prices and
renewable resource growth rates.
There are numerous factors that could impact SCE's rates in addition to the market price impacts
described above. Regulatory changes, plant or technology retirements or additions, and the long-
term impact of the Aliso Canyon leak all can impact SCE rates in the future. To address these
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uncertainties, sensitivity to the SCE results has been modeled assuming a high and low SCE
generation growth rate of 5 percent and 1.5 percent respectively.
The level of the PCIA and the amount of franchise surcharges will impact the cost competiveness of
LACCE. In order to be cost-effective, LACCE power supply costs plus PCIA and other surcharges must
be lower than SCE's generation rates. Over time, the PCIA will vary, but it is expected that it will
decline as market prices increase. The PCIA reflects SCE's own resources and signed contracts.
Once the contracts expire,the related PCIA will disappear. Sensitivity to the PCIA has been modeled
in the high case by assuming the PCIA would increase to reflect a historic high of 2.5 cents per kWh
and remain flat for the 20-year analysis period. For the low case, it was assumed that the PCIA
decreases by 50 percent in year 1 and remains flat for the 20-year analysis period.
Sensitivity Results
Exhibit 41 provides the results of the sensitivity analysis for the 50% Green Scenario, which is the
most likely portfolio for LACCE to pursue. This sensitivity shows that the biggest risk to LACCE is if
the PCIA increases to historic levels, LACCE does not achieve sufficient customer participation or if
market prices fall significantly below their current historical low level.
Exhibit 41
50%Green Portfolio Sensitivity
20-year Levelized Average System Rate(cents per kWh)
SCE Low PC IA
LACCE Low PCIA
SCE High PCIA
LACCE High PCIA
SCE Low Load
LACCE Low Load
SCE High Load
LACCE High Load
SCE Low Power Cost linem
LACCE Low Power Cost
SCE High Power Cost
LACCE High Power Cost
SCE Base Case
LACCE 50%Green
15.00 16.00 17.00 18.00 19.00 20 00 21.00 22.00
Cents per kWh
This sensitivity analysis shows that LACCE rate could be greater than SCE rates if:
• The PCIA becomes larger by orders of magnitude
• LACCE loads are much less than forecast
• Wholesale market prices are much less than current experience
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Each of these three scenarios has a low risk of actually occurring. For example, wholesale market
prices for natural gas/electricity are at all-time lows. The probability of any significant further
lowering of these prices is judged to be very small. The PCIA level should be fairly stable going
forward as regulatory remedies are in play to stabilize the PCIA and the CCA vigilance in this area
has increased markedly. Finally,a relatively high customer opt-out percentage in this Plan has been
assumed when compared to those experienced by operating CCAs. It is very unlikely LACCE loads
will not meet or exceed those assumed in this Plan.
Risks
Regulatory Risks
Regulatory issues continue to arise that may impact the competitiveness of LACCE. However,
California's operating CCAs have worked hard to address any potentially detrimental changes
through effective lobbying and technical support.
New legislation can also impact LACCE. For example, new legislation that recently affected CCAs
are SB 350 and AB 1110. In addition, there are several changes that impact CCEs regarding power
supply procurement and contracting. The CCE-specific changes reflected in SB 350 are generally
positive, providing for ongoing autonomy with regard to resource planning and procurement. CCEs
must be aware, however, of the long term contracting requirement associated with renewable
energy procurement.
Regulatory risks also include the potential for utility generation costs to be shifted to non-
bypassable and delivery charges. LACCE will need to continually monitor and lobby at the Federal,
State and local levels to ensure fair and equitable treatment related to non-bypassable charges.
Participating Cities
LACCE has the possibility of being one of the largest utilities in California. As such, it is prudent to
proceed with caution and implement LACCE's enrollment incrementally. The proposed phase-in
approach allows for LACCE to hire staff and consultants incrementally,and ensure the power supply
procurement, billing and data management process are smooth and with limited issues. This Plan
demonstrates that if LACCE does not add any Cities to its service area, it is still cost competitive with
SCE projected rates. As additional Cities are added, it is expected that LACCE rates will be reduced
even more when compared to SCE's.
Schedule
A schedule for LACCE start-up is provided below.
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Los Angeles Community Choice Energy(LACCE)
Phase 1 Summary Milestone Schedule
2015 2016 2017
Task Name Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar
Task Force Meetings ♦ ♦ ♦ • ♦ ♦ O 4 O O O 4 O O O
Acquire SCE Data(three phases) ♦Order •1st *2nd •Final
i
Business Plan Draft Final
JPA Governing Documents Final
Board Approves Ordinance/Resolution <>Authorization
I
Implementation Plan/Statement of Intent <>Submit to CPUC
JPA Formation 4 Complete
Marketing and Outreach
Negotiate Financing/Line of Credit
Energy Services/Data Management RFQ<> 46.Contracts
CPUC Certification and Launch Date Set ^T 4 Certification by CPUC
Cities Opt-In for Municipal Buildings `)Deadline'(
Negotiate Power Contracts b Contracts
Finalize Cost of Service and Rates
Execute SCE Service Agreement* Q
Integration with SCE
Initial Opt-Out Notices 1st 2ndb
Phase 1 Service Begins Q
Phase launch
lstb O 2nd
Final Opt-Out Notices
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Summary and Recommendations
Rate Impacts and Comparisons
The first impact associated with forming LACCE will be lower electricity bills for LACCE customers.
LACCE customers should see no obvious changes in electric service other than the lower price
and more renewable power procurement. Customers will pay the power supply charges set by
LACCE and no longer pay the higher costs of SCE power supply.
Given this Plan's findings, LACCE's rate setting can establish a goal of providing rates that are
lower than the equivalent rates offered by SCE even under the 50 percent renewable portfolio.
Under the 100 percent renewable portfolio, LACCE customers will pay 6.3 percent more for their
power, but will receive roughly four times as much renewable energy compared to the SCE
product. The projected LACCE and SCE rates are illustrated in Exhibit 42.
Exhibit 42
Indicative Rate Comparison ($/'kWh)
Rate Class SCE Bundled LACCE RPS LACCE 50%Green LACCE 100%Green
Rate* Bundled Rate Bundled Rate Bundled Rate
Residential 17.1 16.2 16.4 18.2
GS-1 16.6 15.7 15.9 17.7
GS-2 15.8 15.0 15.2 16.9
GS-3 14.5 13.8 13.9 15.5
PA-2 12.6 12.0 12.1 13.4
PA-3 10.4 9.9 10.0 11.1
TOU-8 Secondary 13.1 12.4 12.6 14.0
TOU-8 Primary 11.7 11.1 11.2 12.5
TOU-8 Substation 7.5 7.1 7.2 8.0
Total LACCE Rate Savings 5.4% 4.1% (6.3%)
*SCE bundled average rate based on Table 3 in Advice 3319-E-A.
As an alternative to its standard rates with 28 percent renewable power, SCE also offers rates
which feature 50 percent and 100 percent renewable power. For the residential customers, SCE
estimates energy costs to be 3.5 cents per kWh higher for each kWh served on the green rate.
The LACCE rates for 50 percent and 100 percent renewable power for residential customers are
therefore estimated at 12-13% percent lower than SCE's.
Once LACCE gives notice to SCE that it will commence service, LACCE customers will not be
responsible for costs associated with SCE's future electricity procurement contracts or power
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plant investments.6 This is a distinct advantage to LACCE customers as they will now have local
control of power supply costs through LACCE.
Renewable Energy Impacts
A second consequence of forming LACCE will be an increase in the proportion of energy
generated and supplied by renewable resources. The Plan includes procurement of renewable
energy sufficient to meet 50 percent or more of LACCE's electricity needs. The majority of this
renewable energy will be met by new renewable resources. By 2020, SCE must procure a
minimum of 33 percent of its customers' annual electricity usage from renewable resources due
to the state Renewable Portfolio Standard and the Energy Action Plan requirements of the CPUC.
In contrast, LACCE will target 50 percent renewable by 2017 and these resources will likely be
new renewable resources.
Energy Efficiency Impacts
A third consequence of forming LACCE will be an increase in energy efficiency program
investments and activities. The existing energy efficiency programs administered by SCE are not
expected to change as a result of forming LACCE. LACCE customers will continue to pay the public
goods charges to SCE which funds energy efficiency programs for all customers, regardless of
supplier. The energy efficiency programs ultimately planned for LACCE will be in addition to the
level of investment that would continue in the absence of LACCE. Thus, LACCE has the potential
for increased energy investment and savings with an attendant further reduction in emissions
due to expanded energy efficiency programs.
Economic Development Impacts
The fourth consequence of forming LACCE will be enhanced local economic development. The
analyses contained in this Plan has focused primarily on the direct effects of this formation.
However, in addition to direct effects, indirect economic effects are also encountered. The
indirect effects of creating LACCE include the effects of increased local investments, increased
disposable income due to bill savings and improved environmental and health conditions.
Exhibit 43 shows the effects$20 million in electric bill savings will have on the County's economy.
The $20 million rate savings represents the minimum bill savings per year achievable by LACCE
once in full operation. It is estimated that the electric bill savings can create approximately 211
additional jobs in the County with over$9.6 million in labor income. It is also projected that the
total value added will be approximately$15.9 million and output close to $24.2 million.
CCAs may be liable for a share of unbundled stranded costs from new generation,but would then receive associated
Resource Adequacy credits.
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Exhibit 43
$20 Million Rate Savings Effects on County Economy
Impact Type Employment Labor Income Total Value Added Output
Direct Effect 98.3 $3,674,939 $5,376,863 $7,099,612
Indirect Effect 10.4 $608,838 $1,057,593 $1,677,591
Induced Effect 102.1 $5,319,262 $9,472,599 $15,391,851
Total Effect 210.7 $9,603,040 $15,907,056 $24,169,054
These savings are based on the economic construct that households will spend some share of the
increased disposable income on more goods and services.This increased spending on goods and
services will then lead to producers either increasing the wages of their current employees or
hiring additional employees to handle the increased demand.This in turn will give the employees
a larger disposable income which they spend on goods and services and thus repeating the cycle
of increased demand.
In addition to increased economic activity due to electric bill savings, potential local projects can
also create job and economic growth in the local economy. As an example of the macroeconomic
activity caused by local DER deployment, this Plan assumes the installation of fifty crystalline
silicon,fixed mount solar systems with nameplate capacities of 1 MW each for a total capacity of
50 MW. Overall, the building of this one solar project is projected to create $87 million in
earnings and $188 million in output (GDP) in the local economy along with 1,636 jobs during
construction and 14 full-time jobs ongoing. It is anticipated that LACCE will ultimately install a
number of larger local solar projects such as the one described. At full Phase 3 build-out, the
positive economic impacts could be 6-7 times larger than those calculated for Phase 2 operations.
Impact of Resource Plan on Greenhouse Gas (GHG) Emissions
The fifth consequence of forming LACCE will be reduced GHG emissions. The amount of
renewable power in SCE's power supply portfolio is 28 percent' and will rise to 33 percent by
2020. LACCE is committed to reductions in greenhouse gas emissions. Based on power supply
strategy described previously,the estimated GHG emission reductions are forecast to range from
289,080 to 505,890 tons CO2e per year by 2019 assuming a 50 percent RPS target is achieved.
The baseline for comparison is the resource mix used by SCE versus the resource mix that will be
utilized by LACCE. Exhibit 44 details these reductions.
http://www.cpuc.ca.gov/RPS_Homepage/
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Exhibit 44
Baseline Comparison of GHG Reduction by LACCE
2017 2018 2019
Forecast Renewables(50% Renewables) 1,438,275 1,459,854 1,459,854
LACCE (MWH)—Phase 2
LACCE RPS(MWH)—Phase 2 730,029 737,154 737,154
•
Additional Green Power 708,246 722,700 722,700
CO2 reduction—Low(Metric Tons of CO2e) 283,298 289,080 289,080
CO2 reduction—High(Metric tons of CO2e) 495,772 505,890 505,890
These reductions in GHG emissions associated with LACCE operations are significant. Assuming
only Phase 2 loads (all unincorporated County loads) are being met by LACCE, CO2e emissions
associated with in-County electricity use will be reduced by 1-2 percent. At full Phase 3 build-
out, CO2 emissions associated with in-County electricity use will be reduced roughly 12-25
percent by LACCE operations.
Summary
This study concludes that the formation of a CCA in Los Angeles County is financially feasible and
would yield considerable benefits for all participating County residents and businesses. These
benefits could include 4.1 percent lower rates for electricity that is supplied by roughly twice the
amount of renewable resources as SCE. LACCE will reduce GHG emissions by as much as 500,000
tons of CO2e per year by serving only the County's unincorporated areas. At full build-out, a 2
percent rate reduction (a fraction of the total reduction possible)will add 211 jobs,generate over
$24.2 million in additional GDP, and give the County and its residents greater control over their
power supply and energy efficiency programs. The positive impacts on the County and its
inhabitants of forming LACCE are so significant that this effort should be pursued. No likely
combination of sensitivities will change this recommendation.
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Appendix A — Cities/Counties Evaluating CCA
Feasibility
CCA Name Service Area Start Date IOU
Operational
Marin Clean Energy Marin County, Napa May 2010 PG&E
County, part of Contra
Costa and Solano
Counties
Sonoma Clean Power Sonoma County May 2014 PG&E
Lancaster Choice Energy City of Lancaster May 2015 SCE
Clean Power San Francisco City of San Francisco May 2016 PG&E
Peninsula Clean Energy San Mateo County June 2016 PG&E
Exploring/In Process
East Bay Community Energy Alameda County PG&E
TBD Butte County PG&E
TBD City of San Jose PG&E
TBD Contra Costa County PG&E
TBD Humboldt County PG&E
LA Community Choice Energy LA County SCE
TBD Mendocino County PG&E
TBD Monterey County PG&E
TBD Placer County PG&E
TBD Riverside County SCE
TBD San Benito County PG&E
TBD San Bernardino County SCE
TBD San Diego County SDG&E
TBD San Luis Obispo County PG&E
TBD Santa Barbara County SCE/PG&E
Silicon Valley Clean Energy Santa Clara County PG&E
TBD Santa Cruz County PG&E
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Appendix B — CCA Funding Options Prepared by
Public Financial Management, Inc.
This Appendix C is provided by Public Financial Management, Inc.,the energy programs financial
advisor to the Office of Sustainability hired to assist in LACCE start-up activities.
LACCE has funding requirements at each Phase of the program, including initial start-up costs as
well as working capital necessary to bridge the timing lag between initial power purchases and
the receipt of customer revenues. The complexity and availability of funding opportunities is
influenced by the nature of each Phase of the program and the core structural features of the
LACCE program itself. The discussion that follows reviews the current state of the financial
marketplace for CCA programs and the funding options available to LACCE for each Phase of the
program, as well as an overview of how other California CCAs have approached start-up and
launch phase funding requirements.
Overview of Funding Requirements
Start-Up/Phase 1 — Start-Up and Phase 1 funding requirements are estimated to be
approximately $10 million. This amount consists of initial capital needs for infrastructure to
establish the CCA as well as working capital to fund initial power procurement related expenses
and bridge the timing lag between payment deadlines and the receipt of the first customer
revenues. Phase 1 is expected to launch January 1, 2017, but funds will be required pre-launch
starting on or about July 1, 2016 or later if some start-up costs can continue to be covered by
initial County funding to develop the Business Plan.
Phase 2—Phase 2 is scheduled to launch six months after Phase 1 on or about July 1, 2017. Phase
2 funding requirements are estimated to be approximately $40 million largely oriented towards
working capital and credit support for power procurement expenses. Similar to the Phase 1
timing, financing will be required several months prior to the launch of Phase 2. The lending
community will view both Phase 1 and Phase 2 as having elevated risk profiles, given the start-
up nature of the enterprise and uncertainty with respect to customer opt-out rates. On a relative
basis, Phase 1 carries additional funding risk as a result of risks associated with failure to launch
and untested revenue estimates, while the risk profile of Phase 2 should benefit from a limited
history of successful collections and operating results as well as the ability to cure any preliminary
start-up issues during the Phase 1 limited launch.
Current CCA Funding Landscape
The CCA market is rapidly expanding with increasingly proven success. To date, there are four
operational CCAs in California with varying degrees of operating histories; however, all four CCAs
have demonstrated the ability to generate positive operating results. As a result, power
providers have kept pace and expanded their comfort level with CCA counterparty risks, offering
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elongated and more flexible repayment terms for initial power purchases. The same cannot yet
be said for the financial marketplace. To date, the financial counterparties who have gotten
comfortable with CCA counterparty risk are very limited with only 3 to 5 banks currently offering
credit to CCAs in the startup phase. The early adopters were community banks in the CCA service
territory. In recent months a mix of regional and large national banks have shown increased
levels of interest, particularly towards CCAs with (i) longer operating track-records and (ii) larger
service territories. This expanded financial counterparty base should give LACCE comfort that it
will have access to a deeper pool of potential financial counterparties than previous programs.
This is especially important since the LACCE program will dwarf all programs launched to date
with respect to load served and potential customer base and thus require greater dollars.
Why are banks hesitant to lend to CCAs? LACCE will be formed as a Joint Action Agency (JPA)
which is a proven organizational construct within California. Hundreds ofJPAs have been created
in CA and used to access billions in capital dollars over the decades. In particular, public power
utilities in Southern California have sold billions of dollars of tax-exempt bonds and have had
access to bank credit support in the form of letters and lines of credit. The key differentiating
feature between all of these entities and a CCA is a monopoly right to a revenue stream to repay
their creditors. Based on the existing legislative construct, CCAs have opt-out risk which gives
creditors pause for concern. This is the fundamental reason why the financial marketplace has
yet to get comfortable with CCAs on a broad-based basis.
As CCAs have successfully launched across the state and a more robust data set of opt-out history
becomes available, the financial community has been more comfortable to provide credit
support to CCAs. As more and larger opportunities such as LACCE, San Francisco, San Mateo
County and San Diego potentially become available it is driving the financial community to
respond and adapt. To date, the financial community as a whole has essentially been unaware
of the growing CCA opportunity. Additional outreach and large scale public procurement efforts
will continue to educate the marketplace.
With respect LACCE,funding requirements for start-up, Phase 1 and Phase 2 will be difficult funds
to procure from a third party lender without some form of credit support(discussed below). The
lending community will view the Start-up/Phase 1 $10MM investment as high-risk because the
CCA has yet to launch and begin collecting revenues which would be available to repay the lender.
This investment is viewed much like an investment in any other start-up company that may not
get off the ground. Phase 2 needs become a bit less risky as an operating history is established,
but this history will be very limited and a significant amount of risk still exists for any lender.
Future phases will reap the benefits of early Phase success and a reduced risk profile as LACCE
demonstrates a record of operating results.
As a result of these funding challenges, all programs that have launched to date and those in
development have relied on a sponsoring municipality to provide support for obtaining these
needed funds. This support has come in varied forms which are summarized in Exhibit B-1 below:
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Exhibit B-1
Forms of Support
Start-Up Funding
Existing CCAs Requirement' Funding Sources
MCE Clean Energy $2-$5 million
Startup loan from the County of Marin, individual
investors,and local community bank loan.
Loan from Sonoma County Water Authority as well as
Sonoma Clean Power $4-$6 million loans from a local community bank secured by a
Sonoma County general fund guarantee.
CleanPower SF —$5 million Appropriations from the Hetch Hetchy reserve(SFPUC).
Lancaster Choice CCA ^'$2 million Loan from the City of Lancaster general fund.
Peninsula Clean Energy $10-$12 million
San Mateo County has stated a willingness to fund a
$6MM escrow to secure lenders.
1 Source: Respective entity websites and publicly available information.
Funding Option Review
LACCE will have more options than the initial CCA efforts in the state; however, the fundamental
marketplace developments described above will nevertheless influence LACCE's financing
alternatives. This is a very dynamic and rapidly evolving market so what is written here will likely
be different and perhaps more favorable when LACCE moves toward launch.
A review of the current state of options for obtaining funds for these initial phases is detailed
below:
Direct Loan from LA County—LACCE can approach LA County for a loan to fund all or a portion of
the Start-up/Phase 1 and Phase 2 needs. The County would be secured by the CCA revenues
once launched. LA County could expect to be repaid in one to three years for this investment
based on the history of other operational CCAs. LA County would likely assess a risk-appropriate
rate for such a loan which is likely higher than the County earns for funds otherwise invested.
This rate is estimated to be 4.0 percent to 6.0 percent.
Phase 1 needs are wholly County-contained risks in that the CCA is serving power to County
facilities. This is a very controlled risk for the County in that it is essentially both the lender and
the creditor. The opt-out risk is completely in the County's control. While untested, it is possible
that a lender other than the County could be found to fund these needs. Should the County be
willing to offer up additional credit protection in the form of a 3-year agreement to not opt-out
of the CCA, then external funding sources may be more readily available. The loan at that point
would be no different than a loan to the County's general fund, which has ample access to bank
credit, given its high investment grade credit ratings and strong credit profile.
Phase 2 needs are broader and exposed to opt-out risk of customers beyond the County's control.
A direct loan from the County would be the easiest and most reliable approach to funding for
LACCE Phase 2. The County will need to assess such risk appropriately and, if it decides to fund
a loan, should fund at levels that reflect such risk. This has ranged 4.0 percent to 6.0 percent as
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noted above. To date, the tenor of such loans has been relatively short, albeit with somewhat
flexible repayment terms. The County would have other vehicles described below to support the
CCA while limiting its risk.
Collateral Arrangement from LA County—As an alternative to a direct loan from the County, the
County could establish an escrow account to backstop a lender's exposure to the CCA. The
County would agree to deposit funds in an interest-bearing escrow account which the lender
could tap should the CCA fail to pay the lender directly.
The escrow would be interest bearing on behalf of the County so to the extent funds are not used
the County is not forgoing interest earnings or principal. The amount of deposit required is
negotiable with the lenders but could be as high as 50 percent of the loan needs or$12.5 million
to $20 million for Phase 2. This limits the County's exposure to 50 percent vs 100 percent direct
exposure with a loan. This arrangement will attract interest form the existing CCA lending
community and likely bring additional competition via a lending procurement effort.
Loan from a Financial Institution without Support — Market appetite for this option at such an
early stage of the CCA is untested. To date,only CCAs with a more extensive 2 to 3-year operating
history have been able to move away from a supported funding arrangement. LACCE should
nonetheless explore this option.
Vendor Funding — LACCE can pursue arrangements with its power suppliers to eliminate or
reduce the need for or size of funding for the initial Phases. This could come in a number of forms
such as a "lockbox" approach with one power provider or a "credit-sleeving" approach with a
power marketer. However, this approach is less transparent and the associated cost may
outweigh the benefit of eliminating or reducing the need for a bank facility. It has been a very
viable approach for the first CCA programs, but with the expansion of the marketplace it may not
be required.
Revenue Bond Financing—This is not a feasible option at this point given the start-up nature of
the enterprise. Once the CCA is more established (3 to 5 years)and can obtain a credit rating this
could be an avenue to explore for future capital needs. Other CCAs with a longer operating
history will likely explore and establish this marketplace before LACCE.
Summary
Funding for the LACCE program is available and viable in various forms as the financial
marketplace continues to evolve for CCAs. The program should explore all options to determine
which alternatives or combination of alternatives delivers the lowest cost funding.
Phase 1 needs are best supported by LA County as the sole impacted CCA participant. There are
options beyond this, but each involves a significant amount of risk for the counterparty and thus
likely to be available at a higher cost for LACCE.
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Phase 2 needs will greatly benefit from an LA County pledge, but the marketplace may allow
alternatives as noted above.
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Appendix C — Proforma Analyses
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LA County Community Choice Aggregation
Financial Proforma
Portfolio-50%Renewable
2017 2012
Load Data len.11111e July.Dee 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2036 2036
Customer Accounts
Domestic 43 279,428 286,656 287,449 290,158 294,277 299,063 305,491 312,692 320,160 328,122 335,746 341,378 347,105 352,928 358,849 364,870 370,991 377,215 383,543 389,978
Commercial 925 27,673 17,902 28,199 28,489 28,710 28,942 29,276 29,511 29,754 30,031 30,222 30,514 30,809 31,107 31,400 31,711 32,018 32,328 32,641 32,957
Industrial 10 135 135 135 135 134 134 134 134 134 134 134 134 134 134 133 133 133 133 133 133
Lighting&Traffic Control 686 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,283 1,288 1,288 1,283 1,288 1,288 1,288 1,288 1,268 1,268
Agnoulural 64 984 986 989 991 994 997 1,000 1,003 1,005 1,008 1,011 1,014 1,017 1,020 1,023 1,025 1,028 1,031 1,034 1,037
Total Custom's 1,728 309,558 316,966 318,060 321,061 325,412 330,424 337,189 344,628 352,341 360,583 363,401 374,328 380,353 386,477 392,701 399,028 405,459 411,995 418,639 425,393
Energy Solas(MM)
Domestic 86 825,737 1,406,894 1,500,905 1,522,211 1,546,971 1,580,223 1,617,470 1,656,100 1697,285 1,736,723 1,765,859 1,795,484 1825,607 1,856,234 1,887,376 1,919,040 1,951,236 1,983,971 2,017,256 2,051,099
Commercial 23,544 439,958 828,481 836,747 843,298 849,674 859,196 865,918 872,855 880,765 886,220 894,552 902,966 911,464 920,047 928,716 937,421 946,313 955,243 964,262 973,371
Industrial 42,848 222,120 415,784 415,082 413,882 412,796 413,483 413,405 412,993 413,065 412,935 412,646 412,357 412,068 411,279 411,491 411,203 410,915 410,628 410,341 410,054
Lighting&Traffic Control 12,604 19,547 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444
Agricultural 4,917 55,425 103,471 103,750 101,029 104,310 104,591 104,873 105,156 105,439 105,724 106,009 106,295 106,582 106,870 107,159 107,448 107,739 108,030 108,322 108,615
Total Energy 5a105(111Wh) 83,998 1,562,787 2,873,075 2,894,927 2,921,864 2,952,194 2,995,937 3,040,110 3,085,547 3,134,997 3,180,045 3,217,509 3,255,546 3,294,165 3,333,375 3,373,185 3,113,606 3,454,646 3,496,316 3,533,625 3,581,583
2017 2017
CCE Operating Costs len-lune July-Dee 2018 2019 2020 2021 2022 2023 2024 2025 2028 2027 2028 2029 2030 2031 2032 1033 2034 2035 2036
Power Supply $5,115,141 $78,575,785 $147,670,090 $151,208,630 $155,034,198 $159,257,906 5164,317,538 $169,532,598 $175,061,789 5181,154,265 5186,972,696 $192,469,336 $198,332,840 $104,691,824 $211,012,300 $217,680,878 $224,618,939 $231,778,097 5239,348,954 $247 253,173 $255,387,886
Billing&Data Management $12,960 $2,321,688 $4,754,496 $4,770,904 $4,815,913 $4,881,123 $4,956,358 55,052,834 $5,169,415 $5,285,118 $5,408,747 $5,526,017 $5,614,925 $5,705,295 55,297,151 $5,890,512 $5,985,418 $6,081,880 $6,179,928 $6,279,589 $6,380,890
SCE Fees $1,106,742 $230,000 51,559,583 $1,564,964 51,579,727 51,601,133 $1,625,793 $1,659,072 $1,695,616 51,733,627 $1,774,177 $1,812,641 $1,841,803 $1,871,445 $1,901,574 51,931,198 $1,963,325 $1,994,965 $2,027,124 52,059,813 $2,093,040
Technical Services $715,000 $715,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 $1,430,000
Staffing $380,000 $1,215,000 53,396,600 $3,464,532 $3,533,823 53,604,499 $3,676,589 $3,750,121 $3,825,123 $3,901,626 $3,979,658 $4,059,251 54,140,436 $4,223,245 $4,307,710 $4,393,864 $4,441,742 54,521,376 $4,662,804 $4 756,060 $4,851,181
General&Administrative expenses 5160,000 $230,000 $356,000 $312,120 $318,362 $324,730 $331,224 $337,849 $344,606 5351,498 5358,528 5365,698 $373,012 $380,473 $384,082 $395,44 $403,761 $411,836 $420,022 $428,474 $437,043
Debt Service(CU Bonds&Start-up Costs) 53,514,532 $3,514,532 $7,029,064 53,514531 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,531 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $354,532 53,54,531 53,514,532 $3,514,532 53,54,531 $3,514,532
Start-Up Capital 1$5,000,000) SO $0 $0 $0 $0 $0 $0 $0 $0 $0 50 $0 $0 $0 $0 $0 $0 $0 $0 $0
Uncollectibles $58,598 $500,548 $953,462 $954,270 $974531 $997,343 $1,024,971 $971,640 $1,000,666 $1,032,673 $1,063,290 $1,092,187 51,122,723 $1,155,747 51,188,726 $1,223,367 $1,259,328 $1,296,514 $1,335,729 $1,376,631 51,418,720
Total Operating Costs $6,062,973 587,301,553 $167,149,294 $167,219,951 5171,201,087 $175,611,316 $180,877,005 $186,253,651 $192,041,806 5198,403,338 $204,501,628 $210,169,662 $116,370,272 $222,972,560 $229,540.074 $236,461,199 543,657,094 $251,079,199 $256,919,144 $267,098,274 $275,513,292
Other Revenues $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0
Total CCE Revenue Requirement $6,062,973 $87,302,553 $167,149,294 $167,219,951 $171,201,087 $175,611,316 $180,811,005 $186,253,651 5192,041,806 $198,403,338 5204,501,628 $210,269,662 $216,370,272 $222,972,560 $229,540,024 $236,461,199 $243,657,094 5251,079,199 $258,919,144 5267,098,274 $175,513,292
Avenge CCE Rete($/kWh) 50.0530 0.0502 50.0578 50.0586 50.0595 50.0604 $00613 $0.0622 50.0633 $0.043 50.0654 $00665 $0.0677 $0.0689 $0.0701 $0.0714 $0.0722 $00741 50.0795 $00769
Avenge SCE Generation Rate($/kWh) $00684 $0.0692 50.0709 $0.0734 50.0750 50.0762 50.0235 00.0805 50.0823 $0.0041 $0.0858 $0.0875 $0.0894 $0.0908 50.0326 $0.0946 50.0965 50.0986 $0 1008 $0 1029
Total CCE Charges
SCE Non-bypassable Charges $715,270 $13,307,632 $24,496,420 54,588,216 $24,679,691 $14,854,670 $25,142,156 $9,046,076 $9,091,988 $9 163,882 59,219,721 $9,259,956 $9,297,027 $9,332,491 $9,393,272 $9,435,616 $9,477,832 $9,520,054 $9562,314 $9,604,832 59,49,378
CCE Revenue Requirement $6,062,973 $87,302,553 5167,149,294 5167,219,951 5171,201,087 $175,611,316 $180,877,005 $186,253,651 5192,041,806 $198,403,338 5204501,628 $110,269,662 $216,370,272 $222,972,560 $119540,074 $236,461,199 $243,657,094 $251,079,199 $258,919,144 $267,094,274 $275,513,292
Total CCE Generation 8e9e34.Requirement $6,778,244 $100,610,186 $191,45,765 $191,808,177 $195,880,777 5200,465,986 $206,019,161 $195,299,727 $201,133,794 5207,567,220 $113,721,348 $219,529,618 $225,667,299 5232,305,051 $238,933,846 $245,896,815 $253,134,927 $260,599,253 $268,441,467 $276,703,111 $285,162,670
Bundled SCE Revenues $13,222,230 546,000,134 $462,690,313 $476,602,301 $494,417,741 $510,735,421 $530,026,448 5550,333,342 $572,141,453 $594,470,424 $616,770,113 $637,141,478 $658,526,273 5680,869,244 5702,056,698 $725,605,021 $750,044,967 $775,447,673 001,854,54 5829,24,440 5857,632,876
Total CCE Customer Bill Revenues(power Supply and Delivery, $12,680,167 $235,915,032 $443,865,280 5456,869,595 $473,336,572 $488,673,425 5506,842,962 $525,94,140 $546,452,655 $567,524,699 $588,543,233 $607,770,036 $627,923,408 548,959,453 $669,089,958 $691,296,020 5714,336,051 $738,273,377 $763,146,083 $788,981,674 5815,673,177
Savings $542,063 510,085,102 $18,825,033 $19,732,707 $21,041,169 $22,061,996 $23,183,44 54,365,102 $25,64,798 526,945,725 $28,226,879 $29,371,443 $30,602,865 531,909,791 532,966,740 $4,309,054 $35,708,916 $37,174,296 $38,708,485 $40,312,767 $41,964,598
Percent Savings 4.1% 4.1% 41% 4.1% 4.3% 4.3% 4.4% 4,4% 4.5% 4.5% 0.6% 4.6% 4.6% 47% 4.7% 47% 4.8% 4.8% 4.8% 4.9% •9%
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LA County Community Choice Aggregation
Financial Proforma
Portfolio-RPS
2017 2017
Load Date Jen-June July-Dec 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2026 2029 2030 2031 2032 2033 2034 2035 2036
Customer Anovnts
Domestic 43 279,478 286,656 287,449 290,158 294,277 299,063 305,491 312,692 320,160 328,122 335,746 341,378 347,105 352,928 358,849 364,870 370,991 377,215 383,543 389,978
Commercial 925 27,673 27,902 28,199 28,489 28,718 28,942 29,276 29,511 29,754 30,031 30,222 30,514 30,809 31,107 31,408 31,711 32,018 32,328 32,641 32,957
Industrial 10 135 135 135 135 134 134 134 134 134 134 134 134 134 134 133 133 133 133 133 133
Lighting&Traffic Control 686 1,288 1,288 1,280 1,268 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,268 1,288 1,288 1,288 1,208 1,288 1,288 1,288
Agricultural 64 984 986 889 991 994 997 1,000 1,003 1,005 1,008 1,011 1,014 1,017 1,020 1,023 1,025 1,028 1,031 1,034 1,037
' Total Customers 1,728 309,558 316,966 318,060 321,061 325,412 330,424 337,189 341,628 352,341 360,583 368,401 374,328 380,353 386,477 392,701 399,028 405,459 411,995 418,639 425,393
EnegY bks PMW6$
Domestic 86 825,737 1,486,894 1,500,905 1,522,211 1,546,971 1,580,223 1,617,470 1,656,100 1,697,285 1,736,723 1,765,859 1,795,484 1,815,607 1,856,234 1,887,376 1,919,040 1,951,236 1,983,971 2,017,256 2,051,099
Commercial 23,544 439,958 818,482 836,747 843,298 849,674 859,196 865,918 872,855 880,765 886,220 894,552 902,966 911,464 920,047 928,716 937,471 946,313 955,243 964,262 973,371
Industrial 02,848 222,120 415,784 415,082 413,882 412,796 413,483 413,405 412,993 413,065 412,935 412,646 412,357 412,068 411,779 411,491 411,203 410,915 410,628 410,341 410,054
Lighting&Traffic Control 12,604 19,547 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38.444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444
Agricultural 4,917 55,425 103,471 103,750 104,029 104,310 104,591 104,873 105,156 105,439 105,724 106,009 106,295 106,582 106,870 107,159 107,448 107,739 108,030 108,322 108,615
Total Energy Wes(MW6$ 83,998 1,562,787 2,873,075 2,894,927 2,921,864 2,952,190 2,995,937 3,040,110 3,085,547 3,134,997 3,180,045 3,217,509 3,255,546 3,294,165 3,333,375 3,373185 3,413,606 3,454,646 3,496,316 3,538,625 3,581,583
2017 2017
CCE Operating Costs Jen-June July.Dec 2015 2019 2020 2021 2021 2023 2024 2023 2026 2027 2028 2028 2030 2031 2032 1033 2034 2035 1036
Power Supply $5,110,839 $74,072,864 $139,247,657 $143,573,115 5149,887,088 $154,656,623 $163,300,139 5166,177,870 $172 701,936 $179,005,281 5185,335,719 5190,997,414 $197,061,702 $103,479,087 $208,779,585 $215,379,743 $111,252,573 $229,434,741 $236,941,797 $244,780,164 $252,847,304
Billing&Data Management $12,960 $2,321,688 $4,754,496 $4,770,904 $4,815,913 $4,881,173 $4,956,358 $5,057,834 $5,169,415 $5,285,118 $5,408,747 $5,526,017 $5,614,925 $5,705,295 $5,797,151 $5,890,517 $5,985,418 16,081,880 $6,179,928 $6,279,589 $6,380,890
SCE Fees $1,106,742 $230,000 $1,559,583 51,564,964 $1,579,727 $1,601,133 $1,625,793 $1,659,077 $1,695,676 $1,733,627 $1,774,177 $1,812,641 $1,841,803 $1,871,445 51,901,574 $1,932,198 $1,963,315 $1,994,965 $2,027,124 $2,059,813 $2,093,040
Technical Services $715,000 $715,000 $1,430,000 51,430,000 $1,430,000 51,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000
•
• Stabling $380,000 $1,215,000 $3,396,600 $3,464,532 $3,533,823 $3,604,499 $3,676,589 $3,750,121 $3,825,123 $3,901,626 $3,979,658 54,059,251 $4,140,436 $4,223,245 $4,307,710 $4,393,864 $4,481,742 $4,571,376 04,662,804 $4,756,060 $4,851,181
General&Administrative expenses $160,000 $230,000 $356,000 $312,120 $318,362 $324,730 $331,224 $337,849 $344,606 $351,498 $358,528 5365,698 5373,012 $380,473 $388,082 $395,844 $403,761 $411,836 $420,072 $428,474 $437,043
•
•
Debt Service(CCE Bonds&Stan up Costal $3,514,532 $3,514,532 $7,029,064 $3,514,532 $3,514,532 53,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 53,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532
Start up Capital ($5,000,000) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 $0 $0 SO 50 to $0 50
Uncollectibles $58,577 $478,034 $911,349 $916,092 $948,196 $974,337 01,004,884 $954,867 $988,866 $1,021,928 $1,055,105 $1,084,828 $1,116,367 $1,149,683 $1,177,562 $1,211,862 $1,247,506 $1,284,797 $1,323,693 $1,364,267 $1,406,017
Tot.'Operating Costs $6,058,650 $82,777,118 $158,684,749 $159,546,259 $166,028,241 $170,987,026 $176,839,620 $182,882,150 $189,670,154 $196,243,610 $202,856,466 $208,790,381 $215,092,779 $221,753,760 $227,296,195 $234,148,558 $241,278,895 5248,724,126 5256,499,951 $264,612,900 $272,960,008
Other Revenues $0 So $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 SO $0 SO $0 $0 $0
Total CCE Revenue Requirement $6,058,650 $82,777,118 $158,684,749 $159,546,259 $166,028,241 $170,987,026 $176,839,610 $182,882,150 $189,670,154 $196,243,610 $202,856,466 $208,790,381 $215,092,779 $221,753,760 $227,296,195 $234,148,558 $241,278,895 $148,724,126 $256,499,951 $264,612,900 $272,940,008
Av.rege CCE Rate($/kWh) $0.0503 $0.0552 $0.0551 $0.0568 $0.0579 $00590 50.0602 $0.0615 $00626 $0.0638 $00649 $0.0661 $0.0673 $0.0682 $0.0694 $0.0707 $0.0720 $0.0734 $0.0748 $0.0762
/mope 50E Generation Rate 15/kWh) $0.0684 $0.0692 $0.0709 $0.0734 $00750 $0.0767 $0.0785 $0.0805 $0.0823 $0.0841 $0 0858 $0.0875 $0.0894 $0.0908 $0.0926 $0.0946 $0.0965 $0.0986 $01008 $0 1029
Total CCE Chanes
SCE N00-bypassable Charges $715,270 $13,307,632 $24,496,470 $24,588,226 524,679,691 $24,854,670 $25,142,156 $9,046,076 $9,091,988 $9,163,882 $9,219,721 $9,259,956 $9,297,027 $9,332,491 $9,393,772 $9,435,616 $9,477,832 $9,520,054 $9,562,324 $9,604,837 $9,649,378
CCE Revenue Requirement $6,058,650 $82,777,118 5158,684,749 $159,546,259 $166,028,241 $170,987,026 $176,839,620 $182,882,150 $189,670,094 $196,243,610 $202,856,466 5208,790,381 $215,092,779 $221,753,760 $227,256,195 $234,148,558 0241,178,895 $248,724,126 $256,499,951 $264,612,900 $272,960,008
Total CCE Generation Revenue Requirement $6,773,920 $96,064,750 $183,181,219 $184,134,485 $190,707,932 $195,841,697 $201,981,776 $191,928,225 $198,762,142 $205,407,491 $212,076,187 $218,050,337 $224,389,806 $231,086,250 $236,689,967 $243,584,175 $250,756,728 5258,240,180 5266,062,274 $274,217,737 5282,609,386
Bundled 56E Revenues $13,222,230 $246,000,134 $462,690,313 $476,602,301 $494,417,741 $510,735,421 $530,026,048 $550,333,342 5572,141,453 $594,470,424 $616,770,113 $637,141,478 $658,526,273 $680,869,244 $702,056,698 $725,605,074 $750,044,967 $775,447,673 $801,854,568 $829,294,440 $857,637,876
Total CCE Customer gill Revenues(Power Supply and Delivery, $12,507,756 $232,707,322 $437,900,502 $450,715,892 5466,905,427 $482,029,638 5499,947,775 $518,808,581 $538,999,619 $559,786,926 $580,518,962 $599,491,879 5619,373.431 $640,121,821 $660,012,706 $681,921,162 $704,653,177 $728,267,445 $751,802,338 $778,285,044 $804,613,140
Swings $714,474 $13,292,012 $24,769,611 $25,886,409 027,512,314 028,705,753 030,078,674 031,524,761 $33,141,824 $34,663,498 036,251,151 $37,649,600 $39,152,902 $40,747,422 $42,043,993 543,682,912 $45,391,791 $47,180,229 $49,052,230 $51,009,330 $53,024,736
Percent Savings 5.4% 5.4% 5.4% 5.4% 5 6% 5.6% 5 7% 5 7% 5.6% 5.8% 5.9% 5.9% 5 3% 6.0% 6.0% 6 0% 6.1% 6.1% 61% 6.2% 6.2%
Ordinance No.461
98
LA County Community Choice Aggregation
Financial Proforma
Portfolio-100%Renewable
2017 2017
Load Date Jan-lune July-Deo 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2038
Customer AttounU
Domestic 43 279,478 286,656 287,449 290,158 294,277 299,063 305,491 312,692 320,160 328,122 335,746 341,378 347,105 352,928 358,849 364,370 370,991 377,215 383,543 389,978
Commercial 925 27,673 27,902 28,199 28,489 28,718 28,942 29,276 29,511 29,754 30,031 30,222 30,514 30,009 31,107 31,408 31,711 32,018 32,328 32,641 32,957
Industrial 10 135 135 135 135 134 134 134 130 134 134 134 134 134 134 133 133 133 133 133 133
Lighting&Traffic Control 686 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288
Agricultural 64 984 986 989 991 994 997 1,000 1,003 1,005 1,008 1,011 1,010 1,017 1,020 1,023 1,025 1,028 1,031 1,034 1,037
Total Customers 1,728 309,558 316,966 318,060 321,061 325,412 330,424 337,189 344,628 352,341 360,583 368,401 374,328 380,353 386,477 392,701 399,028 405,459 411,995 018,639 425,393
Energy Sales(MWS)
Domestic 86 825,737 1,486,894 1,500,905 1,522,211 1,546,971 1,580,223 1,617,470 1,656,100 1,697,285 1,736,723 1,765,859 1,795,484 1,825,607 1,856,234 1,887,376 1,919,040 1,951,236 1,983,971 2,017,256 2,051,099
Commercial 23,544 439,958 828,482 836,747 843,298 849,674 859,196 865,918 872,855 880,765 886,220 894,552 902,966 911,464 920,047 928,716 937,471 946,313 955,243 964,262 973,371
Industrial 42,848 222,120 415,784 415,082 413,882 412,796 413,483 413,405 412,993 413,065 412,935 412,646 412,357 412,068 411,779 411,491 411,203 410,915 410,628 410,341 010,054
lighting&Traffic Control 12,604 19,547 38,444 38,444 38,444 38,444 38,040 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,404 38,444 38,444 38,444 38,444 38,444 38,444
Agricu kraal 4,917 55,425 103,471 103,750 104,029 104,310 104,591 104,873 105,156 105,439 105,724 106,009 106,295 106,582 106,870 107,159 107,448 107,739 108,030 108,322 108,615
Total Energy Sales(MWh) 83,998 1,562,787 2,873,075 2,894,927 2,921,864 2,952,194 2,995,937 3,040,110 3,085,547 3,130,997 3,180,045 3,217,509 3,255,546 3,294,165 3,333,375 3,373,185 3,413,606 3,450,646 3,496,316 3,538,625 3,581,583
2017 2017
CCE Operating Costs Jan-lune July-Des 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2031 2033 2034 2035 2036
Power Supply 56,007,321 $106,068,728 5198,408,928 $201,450,106 5204,500,269 5208,262,418 5212,887,455 $217,705,763 $222,563,531 5227,944,748 $233,140,721 $237,747,217 $242,462,617 $247,687,986 $252,644,070 5258,072,774 $263,233,933 $269,375,999 5274,892,693 $280,988,647 $286,983,057
Billing&Data Management $12,960 $2,321,688 54,754,496 $4,770,904 $4,815,913 $4,881,173 $4,956,358 $5,057,834 55,169,415 55,285,118 55,408,747 $5,526,017 $5,614,925 55,705,295 $5,797,151 $5,890,517 $5,985,418 $6,081,880 $6,179,928 $6,279,589 56,380,890
SCE Fees $1,106,742 $230,000 51,559,583 51,564,964 $1,579,727 51,601,133 01,615,793 51,659,077 $1,695,676 $1,733,627 51,774,177 $1,812,641 $1,841,803 51,871,445 $1,901,574 $1,932,198 51,963,325 $1,994,965 52,027,124 52,059,813 $2,093,040
Technical Services $715,000 $715,000 $1,430,000 $1,430,000 51,430,000 51,430,000 51,430,000 51,030,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 51,430,000 51,430,000 51,430,000 51,430,000 51,430,000 51,430,000 51,430,000 51,430,000 51,430,000
Staffing $380,000 51,215,000 53,396,600 $3,464,532 $3,533,823 $3,604,499 $3,676,589 $3,750,121 $3,825,123 $3,901,626 53,979,658 $4,059,251 $4,140,436 54,223,245 $4,307,710 $4,393,864 $4,481,742 $4,571,376 54,662,804 54,756,060 54,851,181
General 8.Administrative expenses $160,000 $230,000 5356,000 5312,120 5318,362 5324,730 5331,224 5337,849 $344,606 5351,498 5358,528 $365,698 5373,012 0380,473 $388,082 $395,844 5403,761 5411,836 5420,072 $428,474 $437,043
Debt Service(CCE Bonds&Start-up Costs) $3,514,532 $3,514,532 $7,029,064 $3,514,531 53,514,532 $3,514,532 53514,532 $3,514,532 53,514,532 53,514,532 53,514,532 $3,514,532 $3,514,532 53,514,532 53,514,532 $3,514,532 $3,514,532 53,514,532 $3,514,532 53,514,532 53,514,532
Start Up Capital (55,000,000) 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50
Uncollectibles $63,059 $638,013 51,207,156 $1,205,477 $1,221,862 51,242,366 51,267,821 51,212,506 51,238,174 $1,266,625 $1,294,130 51,318,577 51,343,372 51,370,727 51,396,884 51,425,327 51,452,453 51,484,503 $1,513,447 51,545,310 51,576,696
Total Operating Costs $6,959,614 $114,932,961 $218,141,826 $217,712,635 5220,914,488 5224,860,850 $229,689,773 5234,667,682 5239,781,057 5245,427,774 $250,900,493 5255,773,933 $260,720,698 5266,183,703 5271,380,003 5277,055,055 $282,465,162 5288,865,091 5294,640,601 5301,002,425 $307,266,439
Other Revenues 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50 50
Total CCE Revenue Requirement $6,959,614 5114,932,661 5218,141,826 5217,712,635 $220,914,488 $224,860,850 $229,689,773 5234,667,682 0239,781,057 $245,427,774 5250,900,493 5255,773,933 5260,720,698 $266,183,703 5271,380,003 $277,055,055 5282,465,162 5288,865,091 $290,640,601 $301,002,425 5307,266,439
Avenge CCE Rate(5/kWh) $0 0698 50.0759 50.0752 50.0756 50.0762 50.0767 50.0772 50 0777 50.0783 $0.0789 50.0795 50.0801 500808 50.0814 50.0821 50.0827 50.0836 50.0843 50 0851 50.0858
Avenge SCE Generation Rate(5/kWh) 50.0684 50.0692 $00709 50.0734 500750 50.0767 50.0785 500805 50.0823 50.0841 50.0858 50.0875 50.0894 50.0908 50.0926 50.0946 50.0965 50.0986 501008 501029
Total CCE Charges
SCE Non bypassable Charges $715,270 $13,307,632 $24,496,470 $24,588,226 $24,679,691 $24,854,670 $25,142,156 59,046,076 $9,091,988 59,163,882 09,219,721 $9,259,956 59,297,027 $9,332,491 59,393,772 59,435,616 59,477,832 59,520,054 59,562,324 59,604,837 59,649,378
CCE Revenue Requirement $6,959,614 5114,932,961 5218,141,826 $217,712,635 $220,914,488 $220,860,850 5229,689,773 5234,667,682 5239,781,057 5245,427,774 $250,900,493 $255,773,933 $260,720,698 5266,183,703 $271,380,003 $277,055,055 5282,465,162 5288,865,091 5294,640,601 5301,002,425 $307,266,439
Total CCE Generation Revenue Requirement $7,674,884 5128,240,593 5242,638,296 $242,300,861 5145,594,178 $249,715,521 $254,831,918 $243,713,758 $248,873,045 $254,591,656 $260,120,214 5265,033,889 5270,017,725 $275,516,193 5280,773,774 5286,490,671 5191,942,995 5298,385,145 $304,202,925 5310,607,162 $316,915,817
Bundled SCE Revenues 513,221,230 $246,000,134 $462,690,313 5476,602,301 5494,417,741 $510,735,421 $530,026,448 $550,333,342 $572,141,453 $594,470,424 5616,770,113 5637,141,478 5658,526,273 5680,869,244 5702,056,698 5725,605,074 5750,044,967 5775,447,673 $801,854,568 $829,294,440 5857,637,876
Total CCE Customer Bill Revenues(Power Supply and Delivery' 514,059,453 5261,576,710 5491,583,500 5506,099,214 5520,785,738 5541,823,722 5562,004,460 $583,244,616 5606,076,859 5629,426,882 5652,737,405 5673,995,291 5696,323 220 5719,660,507 5741,707,978 5766,286,884 $791,799,009 $818,320,835 $845,896,040 5874,554,708 5904,154,380
Savings ($837,224) )$15,576,580) (928,893,101) ($28,496,913) (930,367,997) ($31,088,301) ($31,978,011) ($32,911,274) ($33,939,406) ($38,956,858) ($35,987,192) ($36,653,912) ($31,756,050) (539,791,263) (539,651,280) (540,681,810) ($41,754,091) (542,873,162) (544,041,472) ($05,260,268) ($06,516,504)
Percent Savings 63% 6.3% 63% 6.2% 6.1% -61% 60% 6.0% -5.9% -59% -5.8% 4.8% -57% -57% -5.6% -6.6% -5.6% -5.5% -55% -5.5% -5.4%
Ordinance No.461
99
Appendix D — Glossary
aMW: Average annual Megawatt. A unit of energy output over a year that is equal to the energy
produced by the continuous operation of one megawatt of capacity over a period of time (8,760
megawatt-hours).
Basis Difference (Natural Gas):The difference between the price of natural gas at the Henry Hub
natural gas distribution point in Erath, Louisiana, which serves as a central pricing point for
natural gas futures, and the natural gas price at another hub location (such as for Southern
California).
Brown Power: Electricity generated from non-renewable sources or that does not come with a
Renewable Energy Credit (REC).
Buckets: Buckets 1-3 refer to different types of renewable energy contracts according to the
Renewable Portfolio Standards requirements. Bucket 1 are traditional contracts for delivery of
electricity directly from a generator within or immediately connected to California.These are the
most valuable and make up the majority of the RECS that are required for LSEs to be RPS
compliant. Buckets 2 and 3 have different levels of intermediation between the generation and
delivery of the energy from the generating resources.
Bundled Customers: Electricity customers who receive all their services (transmission,
distribution and supply) from the Investor-Owned Utility.
CAISO:The California Independent System Operator.The organization responsible for managing
the electricity grid and system reliability within the former service territories of the three
California IOUs.
California Clean Power(CCP): A private company providing wholesale supply and other services
to CCEs.
California Energy Commission (CEC):The state regulatory agency with primary responsibility for
enforcing the Renewable Portfolio Standards law as well as a number of other, electric-industry
related rules and policies.
California Public Utilities Commission (CPUC): The state agency with primary responsibility for
regulating IOUs, as well as Direct Access (ESP) and CCE entities.
Capacity Factor: the ratio of an electricity generating resource's actual output over a period of
time to its potential output if it were possible to operate at full nameplate capacity continuously
over the same period. Intermittent renewable resources, like wind and solar,typically have lower
capacity factors than traditional fossil fuel plants because the wind and sun do not blow or shine
consistently.
Ordinance No.461
100
CCEAC: Community Choice Energy Advisory Committee - a committee formed to advise the City
of Davis on the best options for pursuing a CCE.
Climate Zone: A geographic area with distinct climate patterns necessitating varied energy
demands for heating and cooling.
Coincident Peak: Demand for electricity among a group of customers that coincides with peak
total demand on the system.
Community Choice Aggregation: Method available through California law to allow Cities and
Counties to aggregate their citizens and become their electric generation provider.
Community Choice Energy: A City, County or Joint Powers Agency procuring wholesale power to
supply to retail customers.
Community Choice Partners: A private company providing services to CCEs in California.
Congestion Revenue Rights (CRRs): Financial rights that are allocated to Load Serving Entities to
offset differences between the prices where their generation is located and the price that they
pay to serve their load. These rights may also be bought and sold through an auction process.
CRRs are part of the CAISO market design.
Demand Response(DR): Electric customers who have a contract to modify their electricity usage
in response to requests from a utility or other electric entity. Typically, will be used to lower
demand during peak energy periods, but may be used to raise demand during periods of excess
supply.
Direct Access: Large power consumers which have opted to procure their wholesale supply
independently of the IOUs through an Electricity Service Provider.
EEI (Edison Electric Institute)Agreement: A commonly used enabling agreement for transacting
in wholesale power markets.
Electric Service Providers (ESP): An alternative to traditional utilities. They provide electric
services to retail customers in electricity markets that have opened their retail electricity markets
to competition. In California the Direct Access program allows large electricity customers to opt-
out of utility-supplied power in favor of ESP-provided power. However, there is a cap on the
amount of Direct Access load permitted in the state.
Electric Tariffs: The rates and terms applied to customers by electric utilities. Typically have
different tariffs for different classes of customers and possibly for different supply mixes.
Enterprise Model: When a City or County establish a CCE by themselves as an enterprise within
the municipal government.
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Federal Tax Incentives:There are two Federal tax incentive programs.The Investment Tax Credit
(ITC) provides payments to solar generators.The Production Tax Credit (PTC) provides payments
to wind generators.
Feed-in Tariff: A tariff that specifies what generators who are connected to the distribution
system are paid.
Forward Prices: Prices for contracts that specify a future delivery date for a commodity or other
security. There are active, liquid forward markets for electricity to be delivered at a number of
Western electricity trading hubs, including NP15 which corresponds closely to the price location
which the City of Davis will pay to supply its load.
Implied Heat Rate:A calculation of the day-ahead electric price divided by the day-ahead natural
gas price. Implied heat rate is also known as the `break-even natural gas market heat rate,'
because only a natural gas generator with an operating heat rate (measure of unit efficiency)
below the implied heat rate value can make money by burning natural gas to generate power.
Natural gas plants with a higher operating heat rate cannot make money at the prevailing
electricity and natural gas prices.
Integrated Resource Plan: A utility's plan for future generation supply needs.
Inter-continental Exchange (ICE): The main electronic trading platform for trading wholesale
electricity and gas contracts in the United States. (Also handles trading in other commodities and
securities.)
Investor-Owned Utility: For profit regulated utilities. Within California there are three IOUs -
Pacific Gas and Electric, Southern California Edison and San Diego Gas and Electric.
ISDA (International Swaps and Derivatives Association): Popular form of bilateral contract to
facilitate wholesale electricity trading.
Joint Powers Agency (JPA): A legal entity comprising two or more public entities. The JPA
provides a separation of financial and legal responsibility from its member entities.
Lancaster Choice Energy(LCE):The most recent California CCE to go-live, exclusively serving the
City of Lancaster in Southern California.
LEAN Energy (Local Energy Aggregation Network): A not-for-profit organization dedicated to
expanding Community Choice Aggregation nationwide.
Load Forecast: A forecast of expected load over some future time horizon. Short-term load
forecasts are used to determine what supply sources are needed. Longer-term load forecasts are
used for budgeting and long-term resource planning.
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Marginal Unit: An additional unit of power generation to what is currently being produced. At
and electric power plant, the cost to produce a marginal unit is used to determine the cost of
increasing power generation at that source.
MCE: Formerly Marin Clean Energy - the first CCE in California serving Cities within and the
Counties of Marin and Napa.
MRTU: CAISO's Market Redesign and Technology Upgrade.The redesigned, nodal (as opposed to
zonal) market that went live in April of 2009.
Net Energy Metering: The program and rates that pertain to electricity customers who also
generate electricity, typically from rooftop solar panels.
Non-Coincident Peak: Energy demand by a customer during periods that do not coincide with
maximum total system load.
NP15: Refers to a wholesale electricity pricing hub-North of Path 15 -which roughly corresponds
to PG&E's service territory. Forward and Day-Ahead power contracts for Northern California
typically provide for delivery at NP15. It is not a single location, but an aggregate based on the
locations of all the generators in the region.
On-Bill Repayment (OBR): Allows electric customers to pay for financed improvements such as
energy efficiency measures through monthly payments on their electricity bills.
Operate on the Margin: Operation of a business or resource at the limit of where it is profitable.
Opt-Out: Community Choice Aggregation is, by law, an opt-out program. Customers within the
borders of a CCE are automatically enrolled within the CCE unless they proactively opt-out of the
program.
Power Cost Indifference Adjustment (PCIA): A charge applied to customers who leave IOU
service to become Direct Access or CCE customers. The charge is meant to compensate the IOU
for costs that it has previously incurred to serve those customers.
PPA (Power Purchase Agreement): The standard term for bilateral supply contracts in the
electricity industry.
Renewable Energy Credits (RECs):The renewable attributes from RPS-qualified resources which
must be registered and retired to comply with RPS standards.
Resource Adequacy (RA): The requirement that a Load-Serving Entity own or procure sufficient
generating capacity to meet its peak load plus a contingency amount (15 percent in California)
for each month.
RPS (Renewable Portfolio Standards): The state-based requirement to procure a certain
percentage of load from RPS-certified renewable resources.
Ordinance No.461
103
Scheduling Coordinator: An entity that is approved to interact directly with CAISO to schedule
load and generation. All CAISO participants must be or have an SC.
Scheduling Agent: A person or service that forecasts and monitors short term system load
requirements and meets these demands by scheduling power resource to meet that demand.
Sonoma Clean Power(SCP): A CCE serving Sonoma County and Sonoma County Cities.
Spark Spread: The theoretical grow margin of a gas-fired power plant from selling a unit of
electricity, having bought the fuel required to produce this unit of electricity. All other costs
(capital, operation and maintenance, etc.) must be covered from the spark spread.
Supply Stack: Refers to the generators within a region, stacked up according to their marginal
cost to supply energy. Renewables are on the bottom of the stack and peaking gas generators on
the top. Used to provide insights into how the price of electricity is likely to change as the load
changes.
Weather Adjusted: Normalizing energy use data based on differences in the weather during the
time of use. For instance, energy use is expected to be higher on extremely hot days when air
conditioning is in higher demand than on days with comfortable temperature. Weather
adjustment normalizes for this variation.
Western Electric Coordinating Council (WECC): The organization responsible for coordinating
planning and operation on the Western electric grid.
Wholesale Power: Large amounts of electricity that are bought and sold by utilities and other
electric companies in bulk at specific trading hubs. Quantities are measured in MWs, and a
standard wholesale contract is for 25 MW for a month during heavy-load or peak hours (7am to
10 pm, Mon-Sat), or light-load or off-peak hours (all the other hours).
WSPP(Western States Power Pool) Agreement: Common, standardized enabling agreement to
transact in the wholesale power markets.
Ordinance No.461
104
ATTACHMENT B
Los Angeles Community Choice Energy(LACCE)
Phase 1 Summary Milestone Schedule
2015 2016 2017
Task Name Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar
Task Force Meetings ♦ ♦ • • ♦ ♦ O Q O Q O Q O O Q
Acquire SCE Data(three phases) .Order .1st ♦2nId 4.Final
Business Plan Draft♦ Q Final
JPA Governing Documents 0 Final
Board Approves Ordinance/Resolution <>Authoriza1tion
Implementation Plan/Statement of Intent OSubmlttooCPUC
JPA Formation Q compiete
Marketing and Outreach '
Negotiate Financing/Line of Credit
Energy Services/Data Management RFD .0Contracts
CPUC Certification and Launch Date Set 4 Certification by CPUC
Cities Opt-In for Municipal Buildings O Deadline
Negotiate Power Contracts contra```
Finalize Cost of Service and Rates
Execute SCE Service Agreement* 0
Integration with SCE
Initial Opt-Out Notices 1st Q 2nd
Phase 1 Service Begins 0 Phase 1 Launch
t�Final Opt-Out Notices sQ2nd
Includes all required forms and Binding Letter of Intent
Ordinance No.461
105 ATTACHMENT C
Start-Up LACCE Cash Needs for CY 2016
August September October November December Total
IOU Fees(including Billing) $780 $0 $0 $2,938 $6,203 $9,921
Consultants
PFM $25,000 $25,000 $25,000 $25,000 $0 $100,000
Legal/Regulatory $50,000 $50,000 $50,000 $50,000 $50,000 $250,000
Financial $25,000 $25,000 $25,000 $25,000 $50,000 $150,000
Advertising/Communication $10,000 $10,000 $20,000
Services $20,000 $20,000 $20,000 $20,000 $20,000 $100,000
Staffing $45,000 $55,000 $55,000 $55,000 $55,000 $265,000
General &Admin $45,000 $35,000 $25,000 $25,000 $25,000 $155,000
CPUC Bond $0 $100,000 $0 $0 $0 $100,000
SCE Bond (Phase 1&2) $0 $259,930 $0 $0 $0 $259,930
Total Budget $210,780 $569,930 $200,000 $212,938 $216,203 $1,409,851
Ordinance No. 461
Page 106
STATE OF CALIFORNIA )
COUNTY OF VENTURA ) ss.
CITY OF MOORPARK )
I, Maureen Benson, City Clerk of the City of Moorpark, California, do hereby certify
under penalty of perjury that the foregoing Ordinance No. 461 was adopted by the City
Council of the City of Moorpark at a regular meeting held on the 7th day of February, 2018
and that the same was adopted by the following vote:
AYES: Councilmembers Mikos, Pollock, Simons, Van Dam, and Mayor Parvin
NOES: None
ABSENT: None
ABSTAIN: None
WITNESS my hand and the official seal of said City this 14th day of February, 2018.
Maureen Benson, City Clerk
(seal)
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