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HomeMy WebLinkAboutAGENDA REPORT 2018 0207 CCSA REG ITEM 11A CITY OF 61.70ORPARK,CALIFORNIA City Council Meeting tof ,- 1 fioi Act N: ITEM 11 .A. , ORDINANCE NO. 461 17-1-771 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 222 Ordinance No. 461 Page 2 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. 223 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 Janice S. Parvin, Mayor ATTEST: Maureen Benson, City Clerk • Attachments: Exhibit A - Joint Powers Agreement Exhibit B — LACCE Business Plan 224 Ordinance No. 461 Page 4 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; 225 Ordinance No. 461 Page 5 (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 • 226 Ordinance No. 461 Page 6 (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. 227 Ordinance No. 461 Page 7 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 228 Ordinance No. 461 Page 8 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. 229 Ordinance No. 461 Page 9 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; 230 Ordinance No. 461 Page 10 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 231 Ordinance No. 461 Page 11 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 232 Ordinance No. 461 Page 12 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; 233 Ordinance No. 461 Page 13 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.). 234 Ordinance No. 461 Page 14 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. 235 Ordinance No. 461 Page 15 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. 236 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 237 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. - 238 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 239 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 240 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 241 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 242 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 243 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. 244 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 teinis, 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. 245 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 246 Ordinance No. 461 Page 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, Gary Saleba President 247 Ordinance No. 461 Page 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 I 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 48 248 Ordinance No. 461 Page 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 SUM MARY 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 70 249 Ordinance No. 461 Page 29 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. 250 Ordinance No. 461 Page 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. 251 Ordinance No. 461 Page 31 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. 252 Ordinance No. 461 Page 32 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 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 253 Ordinance No. 461 Page 33 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. 254 Ordinance No. 461 Page 34 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 percents 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 I http://www.cpuc.ca.gov/RPS_Homepage/ 255 Ordinance No. 461 Page 35 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 COze 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. 256 Ordinance No. 461 Page 36 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. 257 Ordinance No. 461 Page 37 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 petermined 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. 258 Ordinance No. 461 Page 38 Exhibit 2 Retail Energy Share by Rate Class RETAIL ENERGY SHARE BY RATE CLASS UNINCORPORATED COUNTY Public Authority,3% Industrial, 12% 41110. 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. 259 Ordinance No. 461 Page 39 Exhibit 3 Organization Chart Executive Director Administrative Assistant 1 I 1 Assistant Executive Policy& Human Resources Regulatory er Mana Director Manager Manager Power Finance and Rate -ales&Marketin_ Regulatory Procurement Manager Manager IT Manager — Analyst HR Specialist Consultant Accounting& Energy EfficiencyL IT Specialist 1.• Regulatory Billing Analyst I•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: s Power Supply Costs: - Wholesale purchase a 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 260 Ordinance No. 461 Page 40 • 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 261 Ordinance No. 461 Page 41 new requirements may be viewed as overly prescriptive, they apply to all utilities and should not affect the relative competitiveness of LACCE vis-à-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. 262 Ordinance No. 461 Page 42 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. 263 Ordinance No. 461 Page 43 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-5/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 264 Ordinance No. 461 Page 44 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 ESPs. 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.) 265 Ordinance No. 461 Page 45 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% II 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. I 1 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% 266 Ordinance No. 461 Page 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 25,000 20,000 15,000 10,000 5,000 - Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec a Domestic a Small General Service Medium General Service a Large General Service 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. 267 Ordinance No. 461 Page 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 •lndustnal 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. 268 Ordinance No. 461 Page 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 Resource Requirement 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. 269 Ordinance No. 461 Page 49 Exhibit 15 California RPS Requirements as a Percent of Total Power Supply RPS Requirements 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0% 2016 2020 2024 2027 2030 ■Bucket 1 Bucket 2 ■Bucket 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. 270 Ordinance No. 461 Page 50 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 271 Ordinance No. 461 Page 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) 50 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 00 N. N. t, ao co rn rn cr, 0 0 N N N m m V ct Vl .-i N N N N N N N N N N N N N C C > Q C U > i OD C C > 0. _a 6 >.rD 7 0 0- N N v ro U r9 7 ro 0 0 0- al (J/ N to z Q U- 0 0 Q — — z < vi LL 0 272 Ordinance No. 461 Page 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 50 fill ill? 40 30 20 10 0 n n CO Ol O .- N N M V lD r, 00 Ol N M CY ill VD .1 .-i r N N N N N N N N N N N N M M M M M M M M C > Q T i C > a > `- C > Q > C > Q T a) z° co N co z u 2 2 , z u- 2 2 z N 22 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 20 273 Ordinance No. 461 Page 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. 274 Ordinance No. 461 Page 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. 275 Ordinance No. 461 Page 55 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 276 Ordinance No. 461 Page 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 277 Ordinance No. 461 Page 57 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) cc.L 60 50 -11.5 42.0 - 39.5 40 30 20 10 - ---- Spot Market Market PPA. Rerewable Resources Brown Resources Local Renewables 278 Ordinance No. 461 Page 58 Exhibit 18 above includes both spot market and market PPA costs. It is assumed that these costs are primarily for natural gas resources although the specific resource source cannot be determined 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. 279 Ordinance No. 461 Page 59 Exhibit 19 Portfolio 1: Meet RPS Requirements 500 450 1400 350 300 2 250 200 150 100 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. 280 Ordinance No. 461 Page 60 Exhibit 20 Portfolio 2: Serve 50%of Retail Load with Renewables 500 450 =00 350 300 2 250 200 150 100 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 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. 281 Ordinance No. 461 Page 61 Exhibit 21 Portfolio 3: Serve 100%of Retail Load with Renewables 500 450 400 350 300 250 200 50 100 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 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. 282 Ordinance No. 461 Page 62 Exhibit 22 20-year Levelized Base Case Portfolio Costs($/MWh) 70 $66/MWh 65 1.9 60 52 12.4 55 $51/MWh $ /MWh 50 1.9 1.9 45 5.7 6.2 _c 40 2 35 -0 30 25 51.8 20 44.1 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. 283 Ordinance No. 461 Page 63 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. 284 Ordinance No. 461 Page 64 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 285 Ordinance No. 461 Page 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 286 Ordinance No. 461 Page 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 $25,000 287 Ordinance No. 461 Page 67 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 $1,992,059 288 Ordinance No. 461 Page 68 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. 289 Ordinance No. 461 Page 69 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. 290 Ordinance No. 461 Page 70 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. 291 Ordinance No. 461 Page 71 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. 292 Ordinance No. 461 Page 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 0035 0.03 0.025 0 02 0.015 cry 0.01 • 0 005 Y,_... a � 0 2009 2010 2011 2012 2013 • 2015 -0 005 Year -2009 Vintage-2010Vintage---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. 293 Ordinance No. 461 Page 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 021 0.2 0.19 018 Y +^ 0.17 0.16 7//".".%*%\ 0.15 0 14 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 -SCE Ave rage LACCE Rate -LACCE Average Rate 50%Green Historic SCE System Average Rate LACCE Average Rate 100%Green -LACCE Ave rage 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 294 Ordinance No. 461 Page 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 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 (Increases) 5.4% 4.1% (6.3%) *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 DERs 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 -' 295 Ordinance No. 461 Page 75 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/ 296 Ordinance No. 461 Page 76 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 297 Ordinance No. 461 Page 77 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 298 Ordinance No. 461 Page 78 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 299 Ordinance No. 461 Page 79 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 $188 million in output (GDP) in the local economy along with 1,636 jobs during construction and 14 full-time jobs ongoing. LACCE will need 2,000 — 3,000 MW of solar power plants at Phase 3 build-out so the potential employment impact on the County could be very significant. 300 Ordinance No. 461 Page 80 Sensitivity Analysis The aforementioned economic analysis provides the base case analysis of forming LACCE. This base case is predicated on numerous assumptions and estimates that influence the overall results. This section of the Plan will provide the range of impacts that could result from changes in the most significant variables. In addition,this section will address risks that cannot be quantified, but should be addressed and mitigated to the maximum amount possible. Each key assumption is discussed, a band of uncertainty is established and LACCE's rate impacts associated with factoring in this uncertainty is developed for each key variable. Since resource costs are based on forecast natural gas, wholesale market and renewable market prices, it is prudent to look at the sensitivity of the 20-year levelized cost calculation to fluctuations in these projections. Exhibit 39 below shows a summary of low, base, and high resource costs. Exhibit 39 Low, Base and High 20-year Levelized Resource Costs($/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 50 • • 40 30 20 10 0 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 301 Ordinance No. 461 Page 81 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 302 Ordinance No. 461 Page 82 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 PCIA -- 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 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 303 Ordinance No. 461 Page 83 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. 304 Ordinance No. 461 Page 84 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 ♦ ♦ • • • • 0 0 - 0 0 0 0 0 0 0 Acquire SCE Data(three phases) ♦Order •1st •2nd •Final - Business Plan Qraft. O Final JPA Governing Documents V Final Board Approves Ordinance/Resolution `>Authorization I Implementation Plan/Statement of Intent o Submit to CPUC JPA Formation l P Complete Marketing and Outreach Negotiate Financing/Line of Credit Energy Services/Data ManagementRFQ0 •bContracts CPUC Certification and Launch Date Set 4 Certification by CPUC Cities Opt-In for Municipal Buildings Q Deadline I Negotiate Power Contracts VContracts 1 Finalize Cost of Service and Rates Execute SCE Service Agreement* 0 Integration with SCE /I� f Initial Opt-Out Notices 1StV 2ndK Phase 1 Service Begins <>Phasel launch Final Opt-Out Notices 1stl1, 02nd W O U, Ordinance No. 461 Page 85 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 306 Ordinance No. 461 Page 86 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. 6 CCAs may be liable for a share of unbundled stranded costs from new generation,but would then receive associated Resource Adequacy credits. _ 307 Ordinance No. 461 Page 87 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/ 308 Ordinance No. 461 Page 88 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. 309 Ordinance No. 461 Page 89 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 310 Ordinance No. 461 Page 90 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 311 Ordinance No. 461 Page 91 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: 312 Ordinance No. 461 Page 92 Exhibit B-1 Forms of Support Start-Up Funding Existing CCAs Requirement' Funding Sources MCE Clean Ener Startup loan from the County of Marin,individual gy $2 $5 million 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 Ener San Mateo County has stated a willingness to fund a gy $10-$12 million $6MM escrow to secure lenders. '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 313 Ordinance No. 461 Page 93 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. 314 Ordinance No. 461 Page 94 Phase 2 needs will greatly benefit from an LA County pledge, but the marketplace may allow alternatives as noted above. 315 Ordinance No. 461 Page 95 Appendix C — Proforma Analyses 316 Ordinance No.461 Page 96 LA County Community Choice Aggregation Financial Proforma Portfolio-50%Renewable 2017 2017 Load DM. Jan-lune July-Dec 2018 8019 2020 2021 2022 2023 2024 2025 2026 2027 2026 2029 2030 2031 2032 2033 2084 2039 2036 Customer Accounts Domestic 43 279,478 266,656 287,449 290,158 294,277 299,063 305,491 312,692 320,160 328,122 335,746 341,378 347,105 352,928 358,849 364,870 370,991 377,215 383,543 389,978 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 10 135 135 135 135 134 134 134 134 134 134 134 134 134 130 133 133 133 133 133 133 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 1,014 1,017 1,020 1,023 1,025 1,028 1,031 1,034 1,037 Total Cumomen 1,728 309,558 316,966 318,060 321,061 325,012 330,424 337,169 344,628 352,341 360,583 368,401 374,328 380,353 386,477 392,701 399,028 405,459 411,995 418,639 425,393 Enemy Sold(MWA) Domestic 86 825,737 1,086,894 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 1,919,000 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 42,848 222,120 415,784 415,082 413,882 412,796 413,083 413,405 412,993 413,065 412,935 412,646 412,357 412,068 411,779 011,491 411,203 410,915 410,628 410,341 410,050 Lighting&Traffic Control 12,604 19,547 38,444 38,444 38,444 38,440 38,414 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,440 38,444 38,444 38,444 38,444 38,444 38,444 Agricultural 0,917 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(MWhl 83,998 1,562,787 2,873,075 2,894,927 2,921,860 2,952,194 2,995,937 3,000,110 3,085,547 3,134,997 3,180,045 3,217,509 3,255,546 3,294,165 3,333,375 3,373,185 3,413,606 3,454,646 3,496,316 3,538,625 3,581,583 1017 1017 CM Opening 111414 Jai-13.86 808-044 2018 1020 2000 1021 2022 0912 1644 2081 1026 1027 2008 2018 8010 2031 2032 8013 1034 2033 2010 Power supply 55,115,101 $78,575,785 $147,670,090 5151,208,630 $155,034,198 $159,257,906 $164,317,538 5169,532,598 $175,061,789 5181,154,265 $186,972,696 $192,469,336 5198,332,840 0204,691,824 $211,012,300 5217,680,878 5224,618,939 5231,778,097 $239,348,950 1247,253,173 5255,387,886 Billing&Data Management 512,960 $2,321,688 $4,754,496 $4,770,904 $4,815,913 $4,881,173 $4,956,358 $5,057,834 05,169,415 55,285,118 55,408,747 15,526,017 05,614,925 55,705,295 $5,797,151 05,690,517 05,985,418 $6,081,880 56,179,928 $6,279,589 $6,380,890 SCE Pees $1,106,742 5230,000 $1,559,583 $1,564,964 $1,579,727 $1,601,133 61,625,793 $1,653,077 01,695,676 $1,733,627 $1,774,177 $1,812,641 11,811,803 11,871,445 $1,901,574 $1,932,198 $1,303,325 $1,994,965 $2,027,124 $2,059,813 $2,093,040 Technical Services $715,000 1715,000 $1,430,000 51,430,000 51,430,000 01,430,000 51,430,000 01,430,000 $1,430,000 $1,430,000 01,430,000 $1,430,001 $1.430,000 51,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 Staffing 5380,000 $1,215,000 $3,396,600 53464,532 $3,533,823 63.604,499 $3,676,589 53,750,121 $3,825.123 $3,901,626 $3,979,658 $4,059,251 $4,140,436 14,223,245 $4,307,710 $4,393,864 $4,481,742 $4,571,376 $4,662,804 $4,756,060 $4,851,181 General&Administrative expenses $160,000 $230,000 0356,000 $312,120 5318,362 $324,730 0331,224 $337,849 $344,606 $351,498 $358,528 $365,698 5373,012 $380,473 $388,082 5395,844 5403,761 $411,836 $420,072 $428,474 5437,403 Debt Service(CQ Bolds 65329-up Costs) $3,514,532 $3,514,532 07,029,064 $3,514,532 $3,514,532 13.514,532 03,514,532 $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 $3,514,532 $3,514,532 $3,514,532 $3,514,532 $3,514,532 SLart.UPCapoal ($5,000,000( $0 $0 50 SD $O $0 $0 50 $0 $0 $0 $O $O $0 $0 $O $0 $0 $0 SD Uncollectibles $58,598 $500,548 $953,462 $954,270 $974,531 $997,343 $1,024,971 $971,640 $1,000,666 $1,032,673 $1,063,290 $1,092,187 $1,122,723 51,155,747 11,188,726 $1,223,367 01,259,378 $1,296,514 $1,335,729 $1,376,632 $1,418,720 Total Operating Costs $6,062,973 $87,302,553 $167,149,294 $167,219,951 $171,201,087 5175,611,316 1180,877,005 $186,253,651 $192,041,806 $198,403,338 $204;501,628 5210,269,662 0216,370,272 $222,972,560 $229,540,074 $236,461,199 5213,657,096 5251,079,199 0258,919,144 5267,098,270 $275,513,292 Other Revenues $0 $0 $0 $0 50 $0 $0 50 50 $0 $0 $0 $0 $0 $0 $0 to $0 $0 $0 $0 Total CC!Revenue Requirement $6,062,973 $87,302,553 $167,149,294 1167,219,951 5171,201,087 0175,611,316 $180,877,005 0186,253,651 5192,041,806 1198,003,338 5204,501,628 5210,269,662 $216,370,272 $221,972,560 5229,540,074 $236,461,199 0243,657,095 $251,079,199 $258,919,144 0267,098,274 1275,513,292 Average CCE Rate 10/kWh) 50.0530 50.0582 00.0578 50.0586 00.0595 50.0604 $0.0613 $0.0622 $0.0633 $0.0643 50.0654 50.0665 $0.0677 $0.0689 50.0701 $0.0714 00.0727 50.0741 000755 $0.0769 Average 50E Generation Rate(1/kWh) $00684 $0.0692 $0.0709 $0.0730 00.075) $0.0767 00.07115 50.0805 $0.0823 $0.0841 500858 $0.0875 10.0894 10.0906 $00926 50.0946 50.0965 00.0986. $0.1008 $0.1029 Total CCE Charges SCE Nun-bypassable Charges 0715,270 513,307,632 $24,496,470 $24,588,226 $24,679,691 $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 59,393,772 59,435,616 59,477,832 $9,520,054 $9,562,324 $9,604,837 $9,649,378 CCE Revenue Requirement $6,062,973 $87,302,553 $167,149,294 $167,219,951 $171,201.087 5175,611,316 $180,877,005 $186,253,651 0192,041,806 $198,403,338 $204,501,628 5210,269,662 1216,370,272 0222,972,560 $229,540,074 5236,461,199 $243,657,094 $251,079,199 $258,919,144 $267,098,274 $275,513,292 Total CCE Generation Revenue Requirement $6,778,244 $100,610,186 5191,645,765 $191,808,177 $195,880,777 5200,465,086 $206,019,161 $195,293,727 5201,133,794 5207,567,220 $213,721,348 $219,529,618 $225,667,299 5232,305,051 $238,933,846 5245,896.815 5253,134,927 5260,599,253 $268,081,467 5276,703,111 $185,162,670 Bundled SCE Revenues $13,222,230 $246,000,134 $462,690,313 $476,602,301 5494,417,741 5510,735,421 5530,026,448 5550,333,342 $572,141,453 $594,470,424 5616,770,113 5637,141,478 5658,526,273 $680,869,244 $702,056,698 5725,605,074 0750,044,967 5775,447,673 $801,854,568 5829,294,440 $857,637,876 Total CCE Customer Bill Revenues(Power Supply and Delivery, $12,110,167 $235,915,032 5443,865,280 $456,869,595 5073,336,572 $488,673,425 $506,842,962 $525,968,140 1546,452,655 $567,524,699 5588,543,233 $607,770,036 5627,923,408 5648,959,453 5669,089,958 5691,296,020 $714,336,051 $738,273,377 $763,146,083 5788,981,674 1815,673,277 Saving $542,063 110,015,102 $18,175,033 $19,732,707 571,081,169 $22,061,946 $23,183,416 $24,365,202 $25,111,796 126,945,725 $21,226,179 129,371,443 030,602,665 $31,909,791 $32,566,740 $34,309,054 135,701,916 $37,174,216 $38,708,415 $40,312,767 $41,964,998 Parent Savings 4.1% 4.1% 4.1% 4.1% 4.3% 4.3% 4.4% 4.4% 4.5% 4,5% 4.6% 4.6% 4.6% 4.7% 4.7% 4.7% 4.8% 4.8% 4.8% 4.9% 4.9% W Ordinance No 461 Page 97 LA County Community Choke Aggregation Financial Proforma Portfolio-RPS 2017 2017 bel Date Jan-lune duly-Dec 2018 2019 2020 2021 2022 2023 2024 2025 2026 1017 2029 2029 2030 2031 2032 2033 2034 0039 1086 Customer ACM". Domestic 43 279,470 286,656 287,449 290,158 294.277 299,063 305,491 312,692 320,160 328,122 335,746 341,378 347,105 352,928 358.849 364,870 370,991 377,215 383,543 389,978 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 lghting&Traffic Control 686 1288 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 1,208 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 1,014 1,017 1,020 1,023 1,025 1,028 1,031 1,034 1,037 Total Customers 1,728 309,558 316,966 318,060 321,061 325,412 330,424 337,189 344,628 352,341 360,583 368,401 374,328 380,353 386,477 392,701 399,028 405,459 411,995 418,639 425,393 04059756000(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 1,795,480 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 23,544 439,958 828,482 836,747 843,298 849,674 859,196 865,918 872,855 880,765 886,220 894,552 902,966 911,464 920,047 928,716 937,471 946,313 955,243 960,262 973,371 Industrial 42,848 222,120 415,784 415,082 413,882 412,796 413,483 013,405 412,993 413,065 412,935 412,646 412,357 412,068 411,779 411,491 411,203 410,915 410,628 410,341 410,054 11860168 8,Traffic Control 12,604 19,547 38,444 38,444 38,444 38,444 38,404 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 55,425 103,471 103,750 100,029 104,310 104,591 104,873 105,156 105,439 105,724 106,009 106,295 106,582 106,870 107,159 107,448 107,739 108,030 108,322 108,615 Total Energy Sales(MWhl 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 3,413,606 3,454,646 3,496,316 3,538,625 3,581,583 2017 2017 CU 0p.4694 Casts Ian-lune 1613-Dab 3470 2019 1020 2021 1022 2023 2024 1028 2026 2027 1020 1029 2030 2031 1032 1033 1034 2039 2094 Power Supply 55,110,839 574,072,864 $139,247,657 $143,573,115 5149,887,088 5154,656,623 5160,300,239 $166,177,870 $172,701,936 $179,005,281 $185,335,719 5190,997,414 $197,061,702 $203,479,087 $208,779,585 $215,379,743 5221252,573 5229,434,741 $236,941,797 5244,780,164 5252,847,304 Billing&Data Management 512,960 52,321,688 $4,754,496 $4,770,900 54,815,913 54,881,173 54.956,358 $5,057,834 $5,169,415 $5,285,118 $5,408,747 $5,526,017 $5,614,925 $5,705,295 $5,797,151 55,090,517 $5,985,418 56,081,880 $6,179,928 56,279,589 56,380,890 5CE Fees $1,106,742 $230,000 $1,559,583 $1,564,964 $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 $1,901,574 $1,932,198 51,963,325 51,994,965 52,027,124 $2,059,813 $2,093,040 Technical 5e340e0 5715,000 5715,000 $1,430,000 $1,430,000 $1,430,000 51,430,0,4 $1,430,000 $1,430,000 $1,430,000 $1,430,021 $1,430,000 $1,430,002 $1,430,000 $1,430,000 $1,430,060 $1,430,000 $1,430,001 $1,430,000 $1,430,000 $1,430,000 $1,430,000 Staffing $380,00 51,215,000 $3,396,600 $3,464,532 $3,533,823 53,604,499 $3,676,589 $3,750,121 $3,825,123 $3,901,626 $3,979,658 54,059,251 $4,140,436 $4,223,245 $4,307,710 $4,393,864 $4,481,742 $4,571,376 $4,662,804 $4,756,060 54,851,181 General&Administrative expenses $160,000 $230,000 $356,000 $312,120 $318,362 5324,730 $331,224 $337,849 $344,606 $351,498 $358,528 5365,698 $373,012 5380,473 $388,082 $395,844 5403,761 5411,836 5420,072 $428,474 $437,043 Debt Service ka Bonds 6 Stan-up Cos15) $3,514,532 $3,514,532 $7,029,064 $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 $3,514,532 $3,514,532 53,514,532 53,514,532 $3,514,532 $3,514,532 53,510,532 $3,514,532 $3,514,532 Start-Up Capital 1$5,000,0001 $0 $0 $0 $D $0 $0 $0 $0 $0 $D $0 $0 $0 $0 50 50 $0 5o 50 50 Uncollectibles 558,577 5478,034 $911,349 $916,092 5948,7% 5974,337 $1,004,884 $951,867 $988,866 $1,021,928 51,055,105 51,084,828 51,116,367 $1,149,683 $1,177,562 51,211,862 $1,247,506 $1,284,797 $1,323,693 $1,364,267 51,406,017 Total Operating Costs $6,058,650 $82,777,118 5158,684,749 $159,546,259 $166,028,241 $170,987,226 $176,839,620 $182,882,150 $1119,670,154 $196,243,610 5202,856,466 5208,790,381 $215,092,779 $221,753,760 5227,296,195 $234,148,558 $241,278,895 $248,724,126 $256,499,951 $264,612,907 $272,960,008 Other Revenues $0 50 $0 $0 50 $0 $0 $0 50 50 $0 $D $o $0 $0 5o $0 $o 5o 5o $0 Total CCE Revenue Requirement $6,058,650 $82,777,118 $158,684,749 $159,546,259 $166,028,241 $170,987,226 $176,839,620 $182,882,150 5189,670,154 $196,243,610 5202,856,466 $208,790,381 5215,092,779 5221,753,760 $227,296,195 $234,148,558 5241,278,895 5248,724,126 $256,499,951 $264,612,900 5272,960,008 Avenge CCF Rate 15/09651 50.0503 50.0552 50.0551 500568 50.0579 500590 50.0602 50.0615 50.0626 50.0638 50.0649 500661 50.0673 50.0682 50.0694 50.0707 $0.0720 50.0734 50.0748 50.0762 Avenge 509Generation Rate l5/kWhl 500684 50.0692 50.0709 $0.0734 50.0750 $0.0767 $00785 50.0805 50.0823 $0.0801 50.0858 $0.0875 50.0884 50.0908 50.0926 50.0946 $0.0965 500986 50.1005 50.1029 Total CCE atar9as SCE Non-bypassable Charges $715,270 $13,307,632 $24,496,470 524,588,226 $24,679,691 $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 59,435,616 $9,477,832 $9,520,054 $9,562,324 $9,604,837 59,649,378 CCE Revenue Requirement $6,058,650 $82,777,118 $158,684,749 5159,546,259 $156,028,241 $170,987,026 $176,839,620 5182,882,150 $189,670,154 $196,243,610 $202,856,466 5208,790,381 $215,092,779 $221,753,760 $227,296,195 5234,148,558 5241,278,895 5248,724,126 $256,499,951 5264,612,900 $272,960,008 Total CCE 8.000.400 Revenue Requirement 56.773,920 596,080,750 5183,181,219 $184,134,485 $190,707,932 $195,841,697 $201,981,776 $191,928,225 $198,762,142 5205,407,491 $212,076,187 $218,050,337 $224,389,806 5231,086,250 $236,689,967 $243,584,175 $250,756,728 $258,244,180 $266,062,274 $274,217,737 $282,609,386 Bundled SCE Revenues $13,222,230 5246,000,134 5462,690,313 $476,602,301 5494,417,741 5510,735,421 5530,026,448 5550,333,342 5572,141,453 5594,470,424 $616,770,113 5637,141,478 5658,526,273 5680,869,244 $702,056,698 $725,605,074 $750,044,967 5775,447,673 5801,854,568 $829,294,440 $857,637,876 Total CCE Customer 511 Revenues lPower Supply and Delivery. 512,507,756 5232,707,322 $437,900,502 $450,715,892 $466,905,427 $482,029,638 5499,947,775 5518,808,581 $538,999,629 $559,786,926 5580,518,962 $599,491,879 $619,373,431 $640,121,821 $660,012,706 $681,922,162 $704,653,177 5728,267,405 $752,802,338 5778,285,004 $804,613,140 Savings $714,474 513,292,812 $24,789,811 325,886,409 $27,512,314 228,705,783 $30,079,674 231,524,761 $33,141,024 $34,543,498 236,251,151 237,649,600 $39,152,342 $40,747,422 012,043,993 943,092,912 945,391,791 $47,100,099 249,052,230 251,009,396 $53,024,736 Parcant Swings 5.4% 5.4% 5.4% 5.4% 5.6% 5.6% 9.7% 5.7% 5.8% 5-0% 5.9% 5.9% 5.9% 6.0% 6.0% 6.0% 81% 6.1% 6.1% 5.2% 6.2% W 00 Ordinance No.461 Page 98 LA County Community Choice Aggregation Financial Proforma Portfolio-100%Renewable 2017 2017 Load Dna 14n•hate July-DK 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2023 2029 2030 2031 2032 2033 2034 2035 2034 Customer Accounts Domestic 43 279,428 286,656 281,449 290,158 294,211 299.063 305,491 312,692 320,160 328,122 335,746 341,328 347,105 352,928 358,849 364,820 370,991 311,215 383,543 389,928 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 10 135 135 135 135 134 134 134 134 134 134 134 134 130 134 133 133 133 133 133 133 Lighting&Traffic Control 686 1288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,288 1,283 1,288 1,288 1,288 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 1,014 1,017 1,020 1,023 1025 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 380353 386,477 392,701 399,028 405,459 411,395 418,639 425,393 Energy Sola(MW6) 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 1,881,376 1,919,040 1,951,236 1,983,971 2,017,256 2,051,099 Commercial 23,514 439,958 828,482 836,747 843,298 849,674 859,196 865,918 872,855 880,765 886,220 894,552 902,966 911,464 920,047 928,716 937,471 946,313 955,243 964,262 973.371 Industrial 42,848 222,120 415,784 415,082 413,882 412,796 413,483 413,405 412,993 413,065 412,935 412,646 412,357 412,068 411,779 411,491 411,203 410,915 410,628 410,341 410,054 lighting&Traffic Control 12,604 19,547 38,444 38,444 38,444 38,444 33444 38,444 38444 33444 33444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 38,444 33,444 38,444 A4riculiu,:d 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(151Wh) 833998 1,562,787 2873,075 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 3,413,606 3,454,646 3,496,316 3,538,625 3,581,583 $11 2017 CaOpratina Coats 296-!1818 My-Dae 2018 2019 2010 2021 2021 2033 2034 2029 2026 2022 1028 1029 2030 2031 1031 1013 2084 2033 2088 Power Supply 56,007,321 5106,068,728 5198,408,928 $201,450,106 $204,500,269 $208,262,418 $212,887,455 $217,705,763 5222,563,531 $227,944,748 $233,140,721 $237,747,217 $242,462,617 $247,687,986 $252,644,070 $258,072,774 $263,233,933 $269,375,393 $274,892,693 $280,988,647 $286,983,057 Billing&Data Management $12,060 $2,321,688 $4,754,496 $4,770,904 $4,815,913 $4,881,173 54,956,358 55,057,834 $5,169,415 $5,285,118 55,408,747 55,526,017 55,614,925 55,705,295 $5,797,151 $5,890,517 $5,985,418 56,081,880 $6,179,928 $6,279,589 56,380,890 SCE Fees $1,106,742 $230,000 $1,559,583 51,564,964 $1,579,727 $1,601,133 $1,625,793 51,659,077 $1,695,676 $1,733,627 $1,774,177 $1,812,641 51,841,803 $1,871,445 $1,901,574 $1,932,198 $1,353,325 $1,994,965 $2,027,124 $2,053,813 52,093,010 Technical Services $715,000 $715,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 51,430,000 51,430,000 $1,430,000 $1,430,000 $1,430,000 $1,430,000 51,430,000 $1,430,000 $1,430,000 51,430,000 51,430,000 51,430,000 $1,430,000 $1,430,000 Staffing $380,000 $1,215,000 $3,396,600 $3,464,532 $3,533,823 $3,604,499 53,676,589 $3,750,121 $3,825,123 $3,901,626 $3,979,658 $4,059,251 $4,140,436 $4,223,245 $4,307,710 $4,393,864 $4,481,242 54,571,376 54,662,804 $4,756,060 $4,851,181 General&Administrative expenses $160,000 5230,000 5356,000 $312,120 $318,362 $324,730 $331,224 $337,849 $344,606 $351,498 $353,528 $365,698 $373,012 5380,473 $338,032 $395,844 $403,261 3411,836 5420,072 $428,474 $437,043 Debt Service(CQ Bonds&Start-up Costs) $3,514,532 $3,514,532 57,029,064 $3,514,532 $3,514,532 $3,514,532 $3,514,532 53,514,532 $3,514,532 $3,514,532 $3,514,532 53,514,532 $3,514,532 $3,514,532 53,514,532 53,514,532 53,514,532 53.514,532 $3,514,532 $3,514,532 $3,514,532 Start-Up Capital ($5,000,000) $0 $0 $0 50 50 50 $0 SO 50 50 $0 $0 SO $0 50 50 $0 50 S0 $0 Uncollectibles $63,059 5638,013 $1,207,156 $1,205,477 $1,221,862 51,242,366 $1,267,821 51,212,506 51,238,174 51,266,625 51,294,130 51,318,577 $1,343,372 51,370,727 $1,396,021 $1,425,327 $1,452,453 $1,484,503 $1,513,447 $1,545,310 51,576,696 Total Operating Costs $6,959,614 $114,932,961 $218,141,826 $217,712,635 5220,914,488 $224,860,850 $229,689,773 5234,667,682 5239,781,057 $245,427,774 5250,900,493 $255,773,933 $260,720,698 $266,183,703 $271,380,003 $277,055,055 $282,465,162 5238,865,091 5294,640,601 $301,002,425 5307,266,439 Other Revenues $0 SO $0 50 50 50 S0 SO SO 50 SO 50 SO SO 50 SO $0 SD $0 5o SD Total CCE Revenue Requirement 56,959,614 $114,932,361 5218,141,826 $217,712,635 $220,914,488 $224,860,850 $229,689,773 $234,667,682 $239,781,057 $245,427,774 $250,900,493 $255,773,933 $260,720,698 $266,183,703 5271,330,003 5277,055,055 5282,465,162 $288,865,091 $294,640,601 $301,002,425 $307,266,439 Average CCE Rate 15/0036) 50.0698 50.0759 500752 511.0756 50.0762 50.07.7 50.0772 $0.0777 50.0183 $0.0789 $0.0795 $0.0801 90.0808 50.0814 50.0821 50.0827 50.0836 $00843 50.0851 50.0858 Average SCE Generation Rate(5/kWh) 50.0684 50.0692 50.0709 50.0734 50.0750 50.0767 50.0705 50.0805 90.0823 50.0841 50.0858 50.0875 50.0894 50.0908 50.0926 50.0946 50.0965 50.0986 $0.1008 50.1029 Total CCE Chanes SCE%a0bypassable Charges 5715,270 $13,307,632 $24,496,470 $24,588,226 $24,670,691 $24,854,670 525,142,156 59,046,076 59,091,988 $9,163,382 $9,219,721 $9,259,956 $9,297,027 $9,332,491 $9,393,772 59,435,616 $9,477,832 59,520,054 $9,562,324 59,604,837 59,649,378 CCE Revenue Requirement $6,959,614 5114,932,961 5218,141,826 $217,712,635 $220,914,488 $224,860,850 $229,689,773 5234,667,682 5239,781,057 5245,427,774 5250,900,493 5255,773,933 $260,720,698 $266,183,703 5271,380,003 $277,055,055 5282,465,162 $288,865,091 5294,640,601 5301,002,425 5301,266,439 Total CCE Generation Revenue Requirement $7,674,884 5128,240,593 $242638,296 $242,300,861 $245,594,178 $249,715,521 $254,831,928 5243,713,758 $248,873,045 5254,591,656 5260,520,214 $265,033,889 5270,017,725 5275,516,193 $280,773,774 $286,490,671 $291,942,995 $298,385,145 5304,202,925 5310,607,262 5316,915,817 Bundled SCE Revenues $13,222,230 $246,000,134 3462,690,313 $476,602,301 $494,417,741 $510,735,421 $530,026,448 $550,333,342 $572,141,453 $594,470,424 $616,770,113 $637,141,470 $658,526,273 $680,869,244 $702,056,698 $725,605,074 $750,044,367 $775,447,673 $801,854,568 $829,294,440 $857,637,876 Total CCE Customer Bill Revenues(Power Supply and Delivery, $14,059,453 $261,576,714 $491,583,504 $506,099,214 $524,785,738 $541,823,722 $562,004,460 $583,244,616 $606,076,859 $629,426,382 $652,737,405 $673,995,291 $696,323,224 $719,660,501 $741,707,978 $766,286,884 5791,799,043 $818,320,835 5845,896,040 $874,554,708 $904,154,380 Savings ($337,221) ($15,876.580) 020,393,191) ($29,495,913) ($30,367,997) ($31,002,301) ($31,970,011) ($32,911,274) 033,935,406) ($34,956,458) ($35,957,292) 036,353,812) 037,796,968) ($38,791,263) ($39,651,280) (340,681,810) ($41,754,081) (/42,873,162) (546,041,473) ($45,260,268) (546,516,504) Percent Swings -63% -6.3% -6.2% -6.2% -6.1% -6.1% .6.0% i.0% -59% -5.9% -5,8% -5.05 -57% -5.7% .5.6% -5.6% -5.6% -85% -5.5% -5.5% -5,4% • (oJ I-' THIS PAGE LEFT BLANK INTENTIONALLY co Nt 0 Z a) U 0) _ - C N p Oa 320 Ordinance No. 461 Page 100 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. 321 Ordinance No. 461 Page 101 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. 322 Ordinance No. 461 Page 102 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. 323 Ordinance No. 461 Page 103 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. 324 Ordinance No. 461 Page 104 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. 325 Ordinance No. 461 Page 105 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 Acquire SCE Data(three phases) Order w,1st ,,zndFinal Business Plan Draft ,Final JPA Governing Documents Final Board Approves Ordinance/Resolution Authorization I Implementation Plan/Statement of Intent Submit to CPUC JPA Formation Complete Marketing and Outreach Negotiate Financing/Line of Credit l _ Energy Services/Data Management RFa Contracts CPUC Certification and Launch Date Set I Y Certification by CPUC Cities Opt-In for Municipal Buildings Deadline I - Negotiate Power Contracts Contracts Finalize Cost of Service and Rates Execute SCE Service Agreement* < > Integration with SCE Initial Opt-Out Notices I 2nd I'> Phase 1 Service Begins i Phase 1 Launch Final Opt-Out Notices 1st 2nd *Includes all required forms and Binding Letter of Intent. W N 01 Ordinance No. 461 Page 106 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 Lo N J