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Home My WebLink About01-20-2016 City Council Agenda Packet - FullSaratoga City Council Meeting Agenda - Page 1 of 2 SARATOGA CITY COUNCIL SPECIAL MEETING JANUARY 20, 2015 5:15 PM SPECIAL MEETING Administrative Conference Room, City Hall | 13777 Fruitvale Avenue, Saratoga, CA 95070 ORAL COMMUNICATIONS ON NON-AGENDIZED ITEMS Any member of the public may address the City Council for up to three (3) minutes on matters not on the Agenda. The law generally prohibits the City Council from discussing or taking action on such items. However, the Council may instruct staff accordingly. CLOSED SESSION – 5:15 PM CONFERENCE WITH LEGAL COUNSEL—EXISTING LITIGATION (Government Code Section 54956.9(d)(1)) Saratoga et al. v. California Department of Transportation (Santa Clara County Superior Court Case No. 115CV281214) CONFERENCE WITH LEGAL COUNSEL—ANTICIPATED LITIGATION Significant exposure to litigation pursuant to Government Code 54956.9(d)(2). (1 potential case) COMMISSION INTERVIEWS – 5:45 PM TIME NAME COMMISSION VACANCIES INCUMBENT 5:50 p.m. Flora Hoffman Library 3 vacancies (partial term ending Sept. 30, 2017, partial term ending Sept. 30, 2018, partial term ending Sept. 30, 2019) No JOINT MEETING – 6:00 PM Joint Meeting with Santa Clara County Supervisor Joe Simitian Recommended Action: Provide direction on the City of Saratoga budget. ADJOURNMENT Saratoga City Council Meeting Agenda - Page 2 of 2 Certificate of Posting of the Agenda, Distribution of Agenda Packet, & Compliance with Americans with Disabilities Act I, Crystal Bothelio, City Clerk for the City of Saratoga, declare that the foregoing agenda for the meeting of the City Council was posted and available for review on January 14, 2016 at the City of Saratoga, 13777 Fruitvale Avenue, Saratoga, CA 95070 and on the City's website at www.saratoga.ca.us. Signed this 14th day of January 2016 at Saratoga, California. Crystal Bothelio, City Clerk In accordance with the Ralph M. Brown Act, copies of the staff reports and other materials provided to the City Council by City staff in connection with this agenda are available at the office of the City Clerk at 13777 Fruitvale Avenue, Saratoga, CA 95070. Any materials distributed by staff after the posting of the agenda are made available for public review at the office of the City Clerk at the time they are distributed to the City Council. In Compliance with the Americans with Disabilities Act, if you need assistance to participate in this meeting, please contact the City Clerk at 408.868.1269. Notification 24 hours prior to the meeting will enable the City to make reasonable arrangements to ensure accessibility to this meeting. [28 CFR 5.102- 35.104 ADA title II] To view current or previous City Council Meeting videos, visit www.saratoga.ca.us/council City of Saratoga CITY COUNCIL JOINT MEETING Discussion Topics Joint Meeting with Santa Clara County Supervisor Joe Simitian January 20, 2016 | 6:00 p.m. Saratoga City Hall | Administrative Conference Room 6:00 p.m. Introductions 6:15 p.m. Updates from Supervisor Simitian 6:45 p.m. Other Remarks & Wrap Up * The Regular City Council Meeting begins at 7:00 p.m. in the Civic Theater. Joint meeting attendees are invited to attend the Regular Meeting and share an overview of the joint meeting with the public during Oral Communications. Saratoga City Council Meeting Agenda – Page 1 of 5 SARATOGA CITY COUNCIL REGULAR MEETING JANUARY 20, 2016 7:00 PM REGULAR MEETING Civic Theater | 13777 Fruitvale Avenue, Saratoga, CA 95070 PLEDGE OF ALLEGIANCE ROLL CALL REPORT ON POSTING OF AGENDA The agenda for this meeting was properly posted on January 14, 2016. REPORT FROM CLOSED SESSION REPORT FROM JOINT MEETING ORAL COMMUNICATIONS ON NON-AGENDIZED ITEMS Any member of the public may address the City Council for up to three (3) minutes on matters not on the Agenda. The law generally prohibits the City Council from discussing or taking action on such items. However, the Council may instruct staff accordingly. CITY COUNCIL ANNOUNCEMENTS CEREMONIAL ITEMS Commendation for Supervisor Joe Simitian Recommended Action: Present the commendation to Supervisor Joe Simitian. Staff Report Attachment A – Commendation for Santa Clara County Supervisor Joe Simitian SPECIAL PRESENTATIONS Presentation by Midpeninsula Regional Open Space District Recommended Action: Receive a presentation by the Midpeninsula Regional Open Space District representatives. Staff Report Saratoga City Council Meeting Agenda – Page 2 of 5 1. CONSENT CALENDAR The Consent Calendar contains routine items of business. Items in this section will be acted on in one motion, unless removed by the Mayor or a Council Member. Any member of the public may speak on an item on the Consent Calendar at this time, or request that the Mayor remove an item from the Consent Calendar for discussion. Public Speakers re limited to three (3) minutes. 1.1. City Council Meeting Minutes Recommended Action: Approve the City Council minutes for the Special and Regular City Council Meeting on December 16, 2015. Staff Report Attachment A - Minutes for the Special & Regular Meeting on December 16, 2015 1.2. Review of Accounts Payable Check Registers Recommended Action: Review and accept check registers for the following accounts payable payment cycles: 12/16/2015: Period 6 01/05/2016: Period 7 01/12/2016: Period 7 Staff Report Check Register - 12-16-2015 Period 6 Check Register - 1-05-2016 Period 7 Check Register - 1-12-2016 Period 7 1.3. Treasurer’s Report for the Month Ended October 31, 2015 Recommended Action: Review and accept the Treasurer’s Report for the month ended October 31, 2015. Treasurer Report for October 15 1.4. Treasurer’s Report for the Month Ended November 30, 2015 Recommended Action: Review and accept the Treasurer’s Report for the month ended November 30, 2015. Treasurer Report for November 15 1.5. Resolution Authorizing Final Disposition of Certain City Records Recommended Action: Adopt resolution authorizing final disposition of certain city records. Staff Report Attachment 1 - Resolution Authorizing the Final Disposition of Certain City Records Attachment 2 - Exhibit A List of Records Proposed for Final Disposition 1.6. Approval of Contract with NBBM for Janitorial Services Recommended Action: Staff recommends that Council approve a contract with NBBM Services for janitorial services of City facilities in the amount of $67,000. Staff Report Attachment A - Bid Proposal List Attachment B - NBBM Bid Proposal Attachment C - NBBM Service Contract Saratoga City Council Meeting Agenda – Page 3 of 5 1.7. Resolution Updating Unrepresented Employee’s Compensation and Terms of Employment Recommended Action: Adopt the resolution approving compensation and terms of employment for Unrepresented Employees. Staff Report SMO Petition Resolution with Compensation and Terms 1.8. Library Commission Meeting Schedule Recommended Action: Adopt resolution amending the Library Commission meeting schedule. Staff Report Attachment A – Resolution Amending the Library Commission Schedule 2. PUBLIC HEARING Items placed under this section of the Agenda are those defined by law as requiring a special notice and/or a public hearing or those called by the City Council on its own volition. During Public Hearings for appeals, Applicants/Appellants and/or their representatives have a total of ten (10) minutes maximum for opening statements. Members of the public may comment on any item for up to three (3) minutes. The amount of time for public comment may be reduced by the Mayor or by action of the City Council. After public comment, the Applicant/Appellants and/or their representatives have a total of five (5) minutes maximum for closing statements. Items requested for continuance are subject to the City Council's approval at the Council Meeting. 2.1. Consider Actions Related to the formation of a Community Choice Energy Program Recommended Action: 1. Receive report on the attached Draft Silicon Valley Community Choice Energy Technical Study. 2. Conduct a Public Hearing and introduce and waive the first reading of the attached Ordinance to authorize the implementation of a Community Choice Energy Program and find that the project is exempt from CEQA pursuant to CEQA Guidelines 15378(a), 15061(b)(3), and 15308 . Staff Report Draft Technical Study Community Choice Aggregation Ordinance SVCEA Joint Powers Authority Agreement 2.2. Hazardous Vegetation Program Resolution Declaring Abatement of Public Nuisance Recommended Action: Conduct public hearing and adopt resolution. Staff Report Attachment A - Resolution Declaring Abatement of a Public Nuisance as to Specified Properties Containing Hazardous Vegetation Attachment B - 2016 Commencement Report Attachment C - Sample Informational Materials Mailed to Property Owners on Commencement Report Attachment D - Resolution 15-074 Declaring Hazardous Vegetation to be a Nuisance and Setting Public Hearing Date 3. OLD BUSINESS None Saratoga City Council Meeting Agenda – Page 4 of 5 4. NEW BUSINESS 4.1. Amendment to the Policy Pertaining to Naming City-Owned Land and Facilities Recommended Action: Adopt a resolution amending the City policy pertaining to the naming of City-owned land and facilities. Staff Report Attachment A - Resolution Amending Policy Pertaining to Naming City-Owned Land & Facilities 4.2. Resolution Calling for a Collaborative Solution to Homelessness in Santa Clara County Recommended Action: Adopt resolution finding that homelessness is a regional crisis and calling for a collaborative solution in Santa Clara County. Staff Report Attachment A – Resolution Finding that Homelessness is a Regional Crisis in Santa Clara County and Calling for a Collaborative Solution Attachment B – Letter and Sample Resolution from the Cities Association of Santa Clara County CITY COUNCIL ASSIGNMENT REPORTS The list of City Council Assignments is available on the City of Saratoga website at www.saratoga.ca.us/assignments. CITY COUNCIL ITEMS CITY MANAGER'S REPORT ADJOURNMENT CERTIFICATE OF POSTING OF THE AGENDA, DISTRIBUTION OF THE AGENDA PACKET, COMPLIANCE WITH AMERICANS WITH DISABILITIES ACT I, Crystal Bothelio, City Clerk for the City of Saratoga, declare that the foregoing agenda for the meeting of the City Council was posted and available for review on January 14, 2016 at the City of Saratoga, 13777 Fruitvale Avenue, Saratoga, CA 95070 and on the City's website at www.saratoga.ca.us. Signed this 14th day of January 2016 at Saratoga, California. Crystal Bothelio, City Clerk In accordance with the Ralph M. Brown Act, copies of the staff reports and other materials provided to the City Council by City staff in connection with this agenda are available at the office of the City Clerk at 13777 Fruitvale Avenue, Saratoga, CA 95070. Note that copies of materials distributed to the City Council concurrently with the posting of the agenda are also available on the City Website at www.saratoga.ca.us. Any materials distributed by staff after the posting of the agenda are made available for public review at the office of the City Clerk at the time they are distributed to the City Council. These materials are also posted on the City website. In Compliance with the Americans with Disabilities Act, if you need assistance to participate in this meeting, please contact the City Clerk at 408.868.1269. Notification 24 hours prior to the meeting will enable the City to make reasonable arrangements to ensure accessibility to this meeting. [28 CFR 35.102-35.104 ADA title II] Saratoga City Council Meeting Agenda – Page 5 of 5 01/20 Regular Meeting –Joint Meeting with County Supervisor Joe Simitian 02/03 Regular Meeting –Joint Meeting with KSAR 02/05 Council Retreat – 8:30 a.m. -4:30 p.m.– West Valley College 02/17 Regular Meeting – 5:30 p.m. Joint Meeting with Planning Commission and Heritage Preservation Commission, Arts and Crafts Room in Community Center 02/27 3-5 p.m. State of the City --Theater 03/02 Regular Meeting – Joint Meeting with Traffic Safety Commission 03/16 Regular Meeting – Joint Meeting with Parks & Rec Commission and PEBTAC 04/06 Regular Meeting – Joint Meeting with Library Commission, Librarians, and Friends of Library 04/11 Budget Study Session 04/20 Regular Meeting – Joint Meeting with Saratoga Ministerial Association 05/04 Regular Meeting – Joint Meeting with Mt. Winery and Montalvo Arts 05/18 Regular Meeting – Joint Meeting with County Fire and Santa Clara County FireSafe Council 06/01 Regular Meeting – 5:30 p.m. Joint Meeting with HOA’s in Senior Center, Saunders Room 06/15 Regular Meeting – Joint Meeting with Sheriff Office 07/06 Regular Meeting –Joint meeting Hakone Foundation Board 07/20 Meeting Cancelled 08/03 Meeting Cancelled 08/17 Regular Meeting – Joint Meeting with Chamber of Commerce and Destination Saratoga 09/07 Regular Meeting – Joint Meeting with SASCC 09/21 Regular Meeting – Joint Meeting with Youth Commission 10/05 Regular Meeting – 5:30 p.m. Joint Meeting with Saratoga School Districts in Senior Center, Saunders Room 10/19 Regular Meeting – Joint Meeting with Historical Foundation 11/02 Regular Meeting – Joint Meeting with West Valley – Mission Community College Board of Trustees 11/16 Regular Meeting – Joint Meeting with Senator Beall Jr. 12/07 Regular Meeting – Joint Meeting with Representative Low 12/20 Reorganization 12/21 Regular Meeting –Council Norms Study session Unless otherwise stated, Joint Meetings and Study Sessions begin at 6:00 p.m. in the Administrative Conference Room at Saratoga City Hall at 13777 Fruitvale Avenue. CITY OF SARATOGA CITY COUNCIL JOINT MEETING CALENDAR 2016 SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:City Manager’s Office PREPARED BY:Debbie Bretschneider, Deputy City Clerk SUBJECT:Commendation for Santa Clara County Supervisor Joe Simitian RECOMMENDED ACTION: Present the commendation to Santa Clara County Supervisor Joe Simitian. BACKGROUND: Supervisor Joe Simitian is the elected representative of Saratoga on the Santa Clara County Board of Supervisors. Last year, he secured funding for the Saratoga Adult Care Center through the County, ensuring that the Center will stay open to help Saratoga adults of limited means and their families maintain a high quality of life. ATTACHMENTS: Attachment A – Commendation for Santa Clara County Supervisor Joe Simitian 5 COMMENDATION OF THE CITY COUNCIL OF THE CITY OF SARATOGA HONORING SUPERVISOR JOE SIMITIAN WHEREAS, Joe Simitian has served the public for many years, including stints as a member of the California State Senate, the California State Assembly, Mayor of Palo Alto, President of the Palo Alto School Board, and an earlier term on the Santa Clara County Board of Supervisors; and WHEREAS, in 2012, Joe Simitian was elected to the Santa Clara County Board of Supervisors for the Fifth Supervisorial District, which includes Saratoga and other neighboring communities; and WHEREAS, since his election to the Board of Supervisors, Joe has made a concerted effort to stay in touch with Saratoga residents through activities, such as “sidewalk business hours” at the Farmer’s Market, serving as a Celebrity Reader at the Saratoga Library, and meeting with locally elected community leaders; and WHEREAS, during the past three years, Joe has lent his support to Saratoga institutions, such as the Quarry Park, Villa Montalvo, and Hakone Gardens and has helped with efforts to tackle local issues, like airplane noise; and WHEREAS, last year, Joe proposed and secured Santa Clara County funding for the Saratoga Adult Care Center, ensuring that less independent Saratoga adults have help remaining physically and mentally active in an environment that provides opportunities for socialization and stimulation. NOW, THEREFORE, BE IT RESOLVED, that the City Council of the City of Saratoga does hereby recognize and thank Supervisor Joe Simitian for his time and effort in representing the City of Saratoga in Santa Clara County. WITNESS MY HAND AND THE SEAL OF THE CITY OF SARATOGA this 20th of January 2016. ___________________________ E. Manny Cappello, Mayor City of Saratoga 6 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: City Manager’s Office PREPARED BY: Debbie Bretschneider, Acting City Clerk SUBJECT: Presentation by Midpeninsula Regional Open Space District RECOMMENDED ACTION: Receive a presentation by the Midpeninsula Regional Open Space District representatives. BACKGROUND: The Midpeninsula Regional Open Space District representatives will be giving an update on their projects in the San Francisco Bay Area. The Midpeninsula Regional Open Space District exists to acquire and preserve a regional greenbelt of open space land in perpetuity, protect and restore the natural environment, and provide opportunities for ecologically sensitive public enjoyment and education. In 2014, the District was successful in their campaign to pass Measure AA, which is a $300 million general obligation bond, the proceeds of which will be used to fund various projects in open space throughout the District. In this presentation, they will be highlighting their Measure AA funded projects within and around the Saratoga area. 7 SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:City Manager’s Office PREPARED BY:Crystal Bothelio, City Clerk/Assistant to the City Manager SUBJECT:City Council Meeting Minutes RECOMMENDED ACTION: Approve the City Council minutes for the Special and Regular City Council Meeting on December 16, 2015. BACKGROUND: Draft City Council minutes for each Council Meeting are taken to the City Council to be reviewed for accuracy and approval. Following City Council approval, minutes are retained for legislative history and posted on the City of Saratoga website. The draft minutes are attached to this report for Council review and approval. FOLLOW UP ACTION: Minutes will be retained for legislative history and posted on the City of Saratoga website. ATTACHMENTS: Attachment A - Minutes for the Special and Regular City Council Meeting on December 16, 2015 8 Page 1 of 9 MINUTES WEDNESDAY, DECEMBER 16, 2015 SARATOGA CITY COUNCIL SPECIAL MEETING At 5:30 p.m., the City Council Called to order the Special Meeting and conducted a study session on the Library Commission. The Council considered the objectives of the Commission, potential goals for the future, greater involvement with the Library’s teen advisory board, the Commission regular meeting schedule, and Commission budget. The City Council then held a study session on the City Council Norms of Operation. SARATOGA CITY COUNCIL REGULAR MEETING Mayor Cappello called the meeting to order at 7:05 p.m. and led the Pledge of Allegiance. ROLL CALL PRESENT: Mayor Manny Cappello, Vice Mayor Emily Lo, Council Members Mary-Lynne Bernald, Howard Miller, Rishi Kumar ABSENT: None ALSO PRESENT: James Lindsay, City Manager Richard Taylor, City Attorney Crystal Bothelio, City Clerk/Assistant to the City Manager John Cherbone, Public Works Director Mary Furey, Finance & Administrative Services Director Erwin Ordoñez, Community Development Director Michael Taylor, Recreation & Facilities Director Brian Babcock, Administrative Analyst I Kirk Heinrichs, Special Projects Manager REPORT OF CITY CLERK ON POSTING OF AGENDA City Clerk Crystal Bothelio reported that the agenda for this meeting was properly posted on December 11, 2015. COMMUNICATIONS FROM COMMISSIONS & PUBLIC Mayor Cappello shared that the City Council held a study session on the Library Commission and City Council Norms of Operation. Although no decisions were made, the study sessions were productive. Oral Communications on Non-Agendized Items Marcus Breitbacs, one of the owners of Help and Care, introduced his business to the City Council. The owners recently moved the business to Saratoga from Los Gatos. Oral Communications - Council Direction to Staff None Page 2 of 9 Communications from Boards and Commissions None Council Direction to Staff None ANNOUNCEMENTS Council Member Kumar shared that the start of the Young Silicon Valley Coders book camp is on January 10, 2016. The program will run through March and Silicon Valley Tech Day will be June 12, 2016 from 1:00 p.m. to 5:00 p.m. at the Joan Pisani Community Center. Additional information is online at http://www.siliconvalleycoders.org/. He also shared information about Unity in the Community Day on January 17, 2016 at the Joan Pisani Community Center. Last, he announced that the Free Sunday classes at the Joan Pisani Community Center will resume on January 10, 2016. Information is online at www.tinyurl.com/Saratogaclass. Council Member Miller announced that City Hall will be closed from December 24, 2015 to January 3, 2016. Additionally, the Recreation Activity Guide includes a number of programs for all ages and interests, including tap dancing for adults. He also shared that the Saratoga High School Marching Band will be marching in the Tournament of Roses Parade on New Year’s Day. The parade begins at 8:00 a.m. and HGTV will be covering footage of the entire parade. NBC and Univision will be covering parts of the parade. Council Member Bernald shared that the Saratoga Historical Foundation’s exhibit, “Home for the Holidays,” will be open through January 31. The public can see the exhibit on Friday, Saturday, or Sunday from 1:00 p.m. to 4:00 p.m. Additionally, the Saratoga Sister City Organization is coordinating a tour of the Asian Art Museum in San Francisco on January 27, 2016. The tour cost is estimated at $50. For more information, contact Peter Marra. Vice Mayor Lo announced that the Wednesday Farmers Market in the Village is taking a break during the holidays and will resume on January 6, 2016. She also reminded the public to visit Saratoga businesses during the holidays. Mayor Cappello announced the City’s recruitment for the Traffic Safety Commission and Library Commission. CEREMONIAL ITEMS 1. Appointment of Commissioners and Oath of Office Recommended action: Adopt the attached resolution appointing 1 member to the Heritage Preservation Commission and 3 members to the Traffic Safety Commission; and direct the City Clerk to administer the Oath of Office. Page 3 of 9 RESOLUTION NO. 15-073 MILLER/BERNALD MOVED TO ADOPT THE ATTACHED RESOLUTION APPOINTING 1 MEMBER TO THE HERITAGE PRESERVATION COMMISSION AND 3 MEMBERS TO THE TRAFFIC SAFETY COMMISSION; AND DIRECT THE CITY CLERK TO ADMINISTER THE OATH OF OFFICE. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. SPECIAL PRESENTATIONS None CONSENT CALENDAR 2. City Council Meeting Minutes Recommended action: Approve the City Council minutes for the Special City Council Meeting on December 1, 2015 and the Special and Regular City Council Meeting on December 2, 2015. BERNALD/LO MOVED TO APPROVE THE CITY COUNCIL MINUTES FOR THE SPECIAL CITY COUNCIL MEETING ON DECEMBER 1, 2015 AND THE SPECIAL AND REGULAR CITY COUNCIL MEETING ON DECEMBER 2, 2015. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 3. Review of Accounts Payable Check Registers Recommended action: Review and accept check registers for the following accounts payable payment cycles: 11/17/2015: Period 5 11/24/2015: Period 5 12/01/2015: Period 6 12/08/2015: Period 6 BERNALD/LO MOVED TO ACCEPT CHECK REGISTERS FOR THE FOLLOWING ACCOUNTS PAYABLE PAYMENT CYCLES: 11/17/2015 PERIOD 5; 11/24/2015 PERIOD 5; 12/01/2015 PERIOD 6; AND 12/08/2015 PERIOD 6. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 4. Treasurer’s Report for the Month Ended September 30, 2015 Recommended action: Review and accept the Treasurer’s Report for the month ended September 30, 2015. BERNALD/LO MOVED TO ACCEPT THE TREASURER’S REPORT FOR THE MONTH ENDED SEPTEMBER 30, 2015. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. Page 4 of 9 5. Notice of Completion - McFarland Ave Curb and Gutter Rehabilitation - Phase 1 Recommended action: Move to accept the McFarland Ave Curb and Gutter Rehabilitation - Phase 1 as complete and authorize staff to record the Notice of Completion for construction contract. BERNALD/LO MOVED TO ACCEPT THE MCFARLAND AVE CURB AND GUTTER REHABILITATION - PHASE 1 AS COMPLETE AND AUTHORIZE STAFF TO RECORD THE NOTICE OF COMPLETION FOR CONSTRUCTION CONTRACT. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. PUBLIC HEARINGS None OLD BUSINESS None NEW BUSINESS 6. Progress Update - Implementation of Phase I of the Saratoga Village Plan Update Process--- Community Outreach Recommended action: No Action Required Kirk Heinrichs, Special Projects Manager, presented the staff report. Mayor Cappello invited public comment on the item. No one requested to speak. 7. Spring 2016 Issue of The Saratogan Recommended action: Provide direction to staff on the theme and distribution method of the Spring 2016 issue of The Saratogan. Brian Babcock, Administrative Analyst I, presented the staff report. Mayor Cappello invited public comment on the item. No one requested to speak. Page 5 of 9 MILLER/KUMAR MOVED TO DIRECT STAFF TO: PROCEED WITH THE THEME, “COMMUNITY”; INCLUDE WINTER STORM INFORMATION IN THE NEXT ISSUE OF THE NEWSLETTER; SEND A POSTCARD TO RESIDENTS WITH LARGE FONT AND A SIMPLE DESIGN AND PRINT A NOTICE ON THE BACK PAGE OF THE RECREATION ACTIVITY GUIDE WITH SARATOGAN BRANDING TO NOTIFY RESIDENTS THAT THE NEWSLETTER IS AVAILABLE ON THE CITY’S WEBSITE AND PROVIDE INFORMATION ON HOW TO SUBSCRIBE TO RECEIVE THE NEWSLETTER BY EMAIL; USE DISTINCT WEB ADDRESSES TO CAPTURE DATA ABOUT HOW RESIDENTS ARE FINDING THE SARATOGAN AND SUBSCRIBING TO IT; AND PRINT A LIMITED SUPPLY OF NEWSLETTERS FOR DISTRIBUTION AT CITY HALL AND OTHER LOCATIONS THROUGHOUT THE CITY. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 8. Fiscal Year 2016/17 Community Event Grant Program and Street Closure Grant Allocations Recommended action: Approve the recommendations of the Council Finance Committee for FY 2016/17: 1. Allocate $35,000 for the Community Event Grant Program. 2. Allocate $30,000 for two street closures. Brian Babcock, Administrative Analyst I, presented the staff report. Mayor Cappello invited public comment on the item. No one requested to speak. LO/MILLER MOVED TO DIRECT STAFF TO ALLOCATE $35,000 FOR THE COMMUNITY EVENT GRANT PROGRAM AND $30,000 FOR TWO STREET CLOSURES IN THE FISCAL YEAR 2016/17 BUDGET. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 9. BAAQMD's Grant Funding for Plug-In Electric Vehicle Stations Recommended action: 1. Authorize the City Manager or designee to apply for and accept TFCA Electric Vehicle Charging Station Demonstration Project Program and/or Chase! Program grant funds from the Bay Area Air Quality Management District (BAAQMD) for the purpose of installing a DC Fast Charger Plug-In Electric Vehicle Charging Station in the Saratoga Library parking lot, and 2. Direct staff to implement the Plug-In Electric Vehicle Station project if grant is awarded, and 3. Authorize Budget Adjustment to augment the current CIP Electric Vehicle Station project budget. Finance & Administrative Services Director Mary Furey presented the staff report. Mayor Cappello invited public comment on the item. No one requested to speak. Page 6 of 9 RESOLUTIONS NO. 15-071 & 15-072 KUMAR/MILLER MOVED TO: 1) AUTHORIZE THE CITY MANAGER OR DESIGNEE TO APPLY FOR AND ACCEPT TFCA ELECTRIC VEHICLE CHARGING STATION DEMONSTRATION PROJECT PROGRAM AND/OR CHASE! PROGRAM GRANT FUNDS FROM THE BAY AREA AIR QUALITY MANAGEMENT DISTRICT (BAAQMD) FOR THE PURPOSE OF INSTALLING A DC FAST CHARGER PLUG-IN ELECTRIC VEHICLE CHARGING STATION IN THE SARATOGA LIBRARY PARKING LOT; 2) DIRECT STAFF TO IMPLEMENT THE PLUG-IN ELECTRIC VEHICLE STATION PROJECT IF GRANT IS AWARDED; AND 3) AUTHORIZE BUDGET ADJUSTMENT TO AUGMENT THE CURRENT CIP ELECTRIC VEHICLE STATION PROJECT BUDGET. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 10. 2016 Hazardous Vegetation Program Commencement Resolution Recommended action: Approve resolution declaring hazardous vegetation (weeds) as a public nuisance and setting a public hearing on January 20, 2016 to consider objections to the Abatement List. City Clerk Crystal Bothelio presented the staff report. Mayor Cappello invited public comment on the item. No one requested to speak. RESOLUTION NO. 15-074 LO/BERNALD MOVED TO APPROVE RESOLUTION DECLARING HAZARDOUS VEGETATION (WEEDS) AS A PUBLIC NUISANCE AND SETTING A PUBLIC HEARING ON JANUARY 20, 2016 TO CONSIDER OBJECTIONS TO THE ABATEMENT LIST. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 11. Commission Qualifications and Terms Expiring in 2016 Recommended action: Accept the list of Commission qualifications and terms expiring in the 2016 calendar year. City Clerk Crystal Bothelio presented the staff report. Mayor Cappello invited public comment. No one requested to speak. BERNALD/LO MOVED TO ACCEPT THE LIST OF COMMISSION QUALIFICATIONS AND TERMS EXPIRING IN THE 2016 CALENDAR YEAR. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. Page 7 of 9 12. Adoption of City Council Assignments Recommended action: Approve the resolution adopting the 2016 City Council assignments. City Clerk Crystal Bothelio presented the staff report. Mayor Cappello invited public comment on the item. No one requested to speak. RESOLUTION NO. 15-075 MILLER/BERNALD MOVED TO APPROVE THE RESOLUTION ADOPTING THE 2016 CITY COUNCIL ASSIGNMENTS WITH MAYOR CAPPELLO DESIGNATED AS THE ALTERNATE TO THE CITIES ASSOCIATION LEGISLATIVE ACTION COMMITTEE AND SELECTION COMMITTEE. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. 13. Consider Updates to the City Council Handbook, Council & Commission Expense Policy, E- Communications Policy and Council Norms Recommended action: 1. Adopt the resolution approving modifications to Council and Commission Expense Policy 2. Receive report on the Council and Commission E-Communication Policy 3. Review updates to the City Council Handbook 4. Provide direction on any updates to the City Council Norms of Operation City Manager James Lindsay presented the staff report. Mayor Cappello invited public comment. No one requested to speak. RESOLUTION NO. 15-076 MILLER/KUMAR MOVED TO ADOPT THE RESOLUTION APPROVING MODIFICATIONS TO THE COUNCIL AND COMMISSION EXPENSE POLICY AND DIRECTED STAFF TO CORRECT THE TYPO IN THE E- COMMUNICATIONS POLICY IN SECTION III G. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. Page 8 of 9 CITY COUNCIL ASSIGNMENT REPORTS Mayor Manny Cappello Santa Clara County Housing and Community Development (HCD) Council Committee – in January, the Committee will receive applications for public service funding. In February, the Committee will make funding recommendations. Saratoga Area Senior Coordinating Council (SASCC) – during the last meeting, there was a report on SASCC’s capital campaign. Based on initial feedback, it appears that SASCC will be able to reach fundraising goals. Additionally, the Board took action to allocate funds to engage the campaign consultant on the next phase of SASCC’s fundraising efforts. West Valley Sanitation District – during the last meeting, the District Board of Directors discussed changes that the District would like to the Regional Wastewater Facility agreement. Vice Mayor Emily Lo Hakone Foundation Board & Executive Committee – the Board will be meeting on December 17 and a report will be given at the next regular Council Meeting. KSAR Community Access TV Board – KSAR is moving forward on a video program and at the next meeting the Board will discuss a policy and guidelines for content. The Board will also consider whether to add a television monitor in the Civic Theater lobby. Santa Clara County Library Joint Powers Authority – a new foundation for the Santa Clara County Library has been recently formed and board members are currently being recruited and will be ratified at the January 28 meeting. Council Member Mary-Lynne Bernald No report Council Member Howard Miller VTA Board West Valley Cities Alternate – during the Board meeting, former Mountain View Mayor John McAlister spoke on behalf of the North and West county cities interests in conducting a study on State Route 85 as well as taking a strategic look at the entire County, modes of transportation, and projected job growth to address current and future transportation needs. VTA State Route 85 Corridor Policy Advisory Board – during the last meeting, the group discussed policies and objectives for the Board. There is concern about the role of the group and its focus. Council Member Rishi Kumar Saratoga Chamber of Commerce & Destination Saratoga – the Chamber holiday party was held at Claudine’s Wine Experience and was well attended. There was discussion of the Village Creek Trail. Council Member Kumar also shared that he attended an infrastructure symposium in San Francisco. The symposium included representatives from the U.S. Department of Energy who discussed energy-related legislation that has been introduced. CITY COUNCIL ITEMS Council Member Bernald proposed an agenda item to support HR 3965 and 3385, as well as the FAA initiative to address noise concerns of Santa Cruz/Santa Clara/San Mateo/San Francisco Counties. Page 9 of 9 Council Member Miller alternatively suggested that the Mayor draft letters on these issues. Council Member Bernald and Mayor Cappello accepted the proposal to draft letters of support for HR 3965 and 3385 and commenting on the FAA initiative to address noise concerns of Santa Cruz/Santa Clara/San Mateo/San Francisco Counties. CITY MANAGER’S REPORT City Manager James Lindsay announced that City Hall would be closed from December 24, 2015 through January 3, 2016. ADJOURNMENT MILLER/BERNALD MOVED TO ADJOURN THE MEETING AT 9:30 P.M. MOTION PASSED. AYES: CAPPELLO, LO, BERNALD, MILLER, KUMAR. NOES: NONE. ABSTAIN: NONE. ABSENT: NONE. Minutes respectfully submitted: Crystal Bothelio, City Clerk/Assistant to the City Manager City of Saratoga Gina Scott, Accounting Technician SUBJECT: Review of Accounts Payable Check Registers RECOMMENDED ACTION: Review and accept check registers for the following accounts payable payment cycles: 01/12/2016: Period 7 BACKGROUND: The information listed below provides detail for weekly City check runs. Checks issued for $20,000 or greater are listed separately as well as any checks that were void during the time period. Fund information, by check run, is also provided in this report. REPORT SUMMARY: Attached are Check Registers for: Date Ending Check # 12/16/15 129677 129759 83 605,294.43 12/16/15 12/08/15 129676 1/5/16 129760 129817 58 90,841.44 01/06/15 12/16/15 129759 1/12/16 129818 129868 51 500,869.46 01/12/16 01/05/16 129817 Accounts Payable checks issued for $20,000 or greater: Date Check # Issued to Dept.Amount 12/16/15 129726 SCC Office of the Sheriff General PS 414,423.33 12/16/15 129740 Shute, Mihaly & Weinberger General Various 26,308.50 01/12/16 129846 PS 414,423.33 Accounts Payable checks voided during this time period: AP Date Check #Amount 01/05/16 129769 Re-issue check 125.00 10/29/15 129356 Re-issue check 445.20 ATTACHMENTS: Check Registers in the 'A/P Checks By Period and Year' report format PREPARED BY: Law Enforcement Fund Purpose Attorney Services Law Enforcement SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:Finance & Administrative Services 01/05/2016: Period 7 12/16/2015: Period 6 Ending Check #Type of Checks Accounts Payable Issued to Ron Vergis/Tinker Academy Cherie Miller Payee Name Change Moved/Never received Chk Prior Check Register Checks Released Total Checks Amount Reason Status Starting Check #Date SCC Office of the Sheriff General Accounts Payable Accounts Payable 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: Finance & Administrative Services PREPARED BY: Ann Xu, Accountant SUBJECT: Treasurer’s Report for the Month Ended October 31, 2015 RECOMMENDED ACTION: Review and accept the Treasurer’s Report for the month ended October 31, 2015. BACKGROUND: California government code section 41004 requires that the City Treasurer submit to the City Clerk and the legislative body a written report and accounting of all receipts, disbursements, and fund balances. The Municipal Code of the City of Saratoga, Article 2-20, Section 2-20.035 designates the City Manager as the City Treasurer. This report is prepared to fulfill this requirement. The following attachments provide various financial transaction data for the City of Saratoga’s Funds collectively as well as specifically for the City’s General (Operating) Fund, including an attachment from the State Treasurer’s Office of Quarterly LAIF rates from the 1st Quarter of 1977 to present. FISCAL STATEMENT: Cash and Investments Balance by Fund As of October 31, 2015, the City had $292,587 in cash deposit at Comerica bank, and $15,031,682 on deposit with LAIF. Council Policy on Working Capital Reserve Funds, adopted on April 20, 1994, states that: for cash flow purposes, to avoid occurrence of dry period financing, pooled cash from all funds should not be allowed to fall below $2,000,000. The total pooled cash balance as of October 31, 2015 is $15,031,682 and exceeds the minimum limit required. The following Fund Balance schedule represents actual funding available for all funds at the end of the monthly period. This amount differs from the above Cash Summary schedule as assets and liabilities are components of the fund balance. As illustrated in the summary below, Total Unrestricted Cash is adjusted by the addition of Total Assets less the amount of Total Liabilities to arrive at the Ending Fund Balance – which represents the actual amount of funds available. Unrestricted Cash Comerica Bank 292,587$ Deposit with LAIF 14,739,095$ Total Unrestricted Cash 15,031,682$ Cash Summary 38 Fund Balance Designations In accordance with Governmental Accounting Standards Board (GASB) Statement No. 54, Fund Balance Reporting and Governmental Fund Type Definitions, the components of fund balance are categorized as follows: “non-spendable fund balance”, resources that are inherently non-spendable from the vantage point of the current period; “restricted fund balance”, resources that are subject to enforceable legal restrictions; “committed fund balance”, resources whose use is constrained by limitations the government imposes upon itself through formal action at its highest level of decision making and remains binding unless removed in the same manner; “assigned fund balance”, resources that reflects a government’s intended use of resources, such intent would have to be established at either the highest level of decision making, by a body, or an official designated for that purpose; and “unassigned fund balance”, net resources in excess of what can properly be classified in one of the other four categories. Currently, the City’s fund balance reserves fall into one of the four spendable categories; restricted, committed, assigned, or unassigned fund balance. CONSEQUENCES OF NOT FOLLOWING RECOMMENDED ACTION The City would not be in compliance with Government Code Section 41004. ATTACHMENTS A – Change in Total Fund Balances by Fund under GASB 54 B – Change in Total Fund Balances by CIP Project C – Change in Cash Balance by Month D – Local Agency Investment Fund (LAIF) Quarterly Apportionment Rates + Total Unrestricted Cash 15,031,682$ Plus: Assets 733,314 Less: Liabilities (2,654,845) Ending Fund Balance 13,110,151$ Adjusting Cash to Ending Fund Balance 39 ATTACHMENT A CHANGES IN TOTAL FUND BALANCE UNDER GASB 54 Fund Description Fund Balance 7/1/15 Increase/ (Decrease) Jul-Sep Current Revenue Current Expenditure Transfer In Transfer Out Fund Balance 10/31/15 General Fund Restricted Fund Balances: Environmental Services Reserve 363,182 - - - - - 363,182 Committed Fund Balances: Hillside Stability Reserve 1,000,000 - - - - - 1,000,000 Assigned Fund Balances: Future Capital Replacement & Efficiency Project Reserve 1,777,896 - - - - 1,777,896 - Facility Reserve 900,000 - - - - - 900,000 Carryforwards Reserve 176,560 - - - - - 176,560 Unassigned Fund Balances:- Working Capital Reserve 2,007,545 - - - - - 2,007,545 Fiscal Stabilization Reserve 1,000,000 - - - - - 1,000,000 Development Services Reserve 713,891 - - - - 60,000 653,891 Compensated Absences Reserve 208,167 - - - - - 208,167 Other Unassigned Fund Balance Reserve (Pre YE distribution 1,659,490 (2,708,093) 1,232,146 1,990,969 - 64,760 (1,872,186) General Fund Total 9,806,731 (2,708,093) 1,232,146 1,990,969 - 1,902,656 4,437,159 Special Revenue Landscape/Lighting Districts 867,643 (95,241) 14,008 64,413 - - 721,997 Capital Project Street Projects 1,041,388 (150,579) 18,220 128,899 1,088,760 - 1,868,892 Park and Trail Projects 888,565 (424,350) - 42 328,068 64,068 728,173 Facility Projects 347,618 (90,781) - 18,383 233,896 - 472,351 Administrative Projects 367,869 (18,446) 2,655 3,858 285,000 - 633,222 Tree Fund Projects 56,248 992 - - - - 57,240 Park In-Lieu Fees Projects 276,753 69,001 - 143,302 31,000 - 233,452 CIP Grant Street Projects 8,294 (41) - 855 - - 7,397 CIP Grant Park & Trail Projects 17,427 (4,618) - - - - 12,809 Gas Tax Fund Projects 854,615 164,552 55,508 21,488 33,878 33,878 1,053,188 CIP Fund Total 3,858,778 (454,270) 76,384 316,825 2,000,602 97,946 5,066,723 Debt Service Library Bond 906,600 (693,697) 3,978 - - - 216,881 Internal Service Fund Liability/Risk Management 291,263 (113,779) 82,694 9,042 - - 251,136 Workers Compensation 314,525 (3,360) 45,752 42,819 - - 314,097 Office Support Fund 75,075 1,589 14,866 3,334 - - 88,196 Information Technology Services 260,322 (4,437) 119,405 49,888 - - 325,402 Equipment Maintenance 115,564 19,008 68,751 27,446 - - 175,877 Building Maintenance 268,326 45,513 225,681 93,489 - - 446,031 Equipment Replacement 649,498 33,372 35,208 612 - - 717,465 Technology Replacement 194,101 29,465 31,250 5,629 - - 249,187 Building FFE Replacement - 50,000 50,000 - - - 100,000 - Total City 17,608,426 (3,893,932) 2,000,124 2,604,466 2,000,602 2,000,602 13,110,151 40 ATTACHMENT B FUND BALANCES BY CIP PROJECT CIP Funds/Projects Fund Balance 7/1/15 Increase/ (Decrease) Jul-Sep Current Revenue Current Expenditure Transfer In Transfer Out Fund Balance 10/31/15 Street Projects Annual Street Resurfacing - 24,761 18,220 18,508 64,760 - 89,234 Residential Street Construction 243,612 (142,909) - 32,317 300,000 - 368,385 Roadway Maintenance and Repairs - (19,711) - 29,906 375,000 - 325,383 EV Stations - - - - 25,000 - 25,000 Roadway Safety & Traffic Calming 27,114 (8,698) - 593 50,000 - 67,822 Highway 9 Safety Project - Phase IV 121,019 - - - - - 121,019 Beaumont Traffic Circle - - - - 30,000 - 30,000 Village LED Streetlights 5,007 - - - - - 5,007 Annual Sidewalks Project 46,702 (3,015) - 45,455 50,000 - 48,232 Annual Storm Drain Upgrade 9,352 (1,006) - 2,121 50,000 - 56,225 Village-Streetscape Improvements 25,059 - - - 50,000 - 75,059 Village Sidewalk Curb & Gutter Construction - Phase II 85,281 - - - - - 85,281 EL Camino Grande SD Pump 150,000 - - - - - 150,000 Saratoga Hills SD Pump - - - - 44,000 - 44,000 Storm Drain Capture Device 30,000 - - - - - 30,000 Wildcat Creek Outfall 40,000 - - - - - 40,000 Fourth Street Bridge 100,000 - - - - - 100,000 Quito Road Bridge Replacement Design 59,500 - - - - - 59,500 Bridge Maintenance & Repairs - - - - 50,000 - 50,000 Underground Project 98,744 - - - - - 98,744 Total Street Projects 1,041,388 (150,579) 18,220 128,899 1,088,760 - 1,868,892 Parks & Trails Projects Park/Trail Repairs 67,929 - - - - 64,068 3,861 Park Pathway Repairs - - - - 50,000 - 50,000 Sustainable Landscaping - - - - 89,068 - 89,068 Hakone Garden Matching Funds 193,991 (58,968) - 42 - - 134,980 Hakone Garden Upper Moon House 125,000 - - - - - 125,000 Quarry Park Plan Implement 290,768 (361,622) - - 90,000 - 19,146 Quarry Park Row Acquisition 100,000 - - - - - 100,000 Joe's Trail at Saratoga/De Anza 33,997 - - - - - 33,997 Guava/Fredericksburg Entrance 45,880 - - - - - 45,880 Saratoga Village Creek Trail - Design 31,000 (3,760) - - 18,000 - 45,241 Saratoga Village Creek Trail - Construction - - - - 81,000 - 81,000 Total Parks & Trails Projects 888,565 (424,350) - 42 328,068 64,068 728,173 Facility Projects Facility Projects 43,500 (39,150) - 4,350 - - - Security Locks 53,007 - - - - - 53,007 City Hall Emergency Power Backup 325 (108) - 217 - - - Master Switch - Electrical Board 73,498 (46,755) - 9,636 - - 17,107 ENG/CDD Window Replacement - - - - 40,000 - 40,000 Civic Theater Improvements 87,882 1,229 - 1,387 - - 87,723 Civic Theater Master Plan Improvements 64,900 - - 2,793 - - 62,108 Theater Boiler Replacement - - - - 90,000 - 90,000 Theater Rooftop Duct Work - - - - 90,000 - 90,000 Pre-School Playground Structure 10,458 (5,996) - - - - 4,462 SPCC Furniture & Fixtures - - - - 13,896 - 13,896 McWilliams House Improvements - Phase II 3,578 - - - - - 3,578 Library Building Exterior Maintenance Projects 10,470 - - - - - 10,470 Total Facility Projects 347,618 (90,781) - 18,383 233,896 - 472,351 41 ATTACHMENT B (Cont.) FUND BALANCES BY CIP PROJECT CIP Funds/Pro jects Fund Balance 7/1/15 Increase/ (Decrease) Jul-Sep Current Revenue Current Expenditure Transfer In Transfer Out Fund Balance 10/31/15 Administrative Projects Financial System Upgrade 3,534 - - - - - 3,534 COMB Document Imaging Project 57,894 (4,478) - 2,605 - - 50,811 City Website/Intranet - - - - 75,000 - 75,000 Development Technology 22,928 12,131 2,655 - - - 37,714 Trak-It Software Upgrade - - - - 60,000 - 60,000 LLD Initiation Match Program 49,000 - - - - - 49,000 Horseshoe Beautification 25,000 - - - - - 25,000 General Plan Update 100,000 - - - - - 100,000 Village Façade Program 20,321 - - - - - 20,321 Village Specific Plan Update - (2,077) - 1,253 100,000 - 96,670 Wildfire Protection Plan 25,000 - - - - - 25,000 Risk Management Project Funding 64,192 (24,020) - - 50,000 - 90,171 Total Administrative Projects 367,869 (18,446) 2,655 3,858 285,000 - 633,222 Tree Fund Projects Citywide Tree Planting Program 33,248 867 - - - - 34,115 Tree Dedication Program 21,250 125 - - - - 21,375 SMSCF Tree Donation Program 1,750 - - - - - 1,750 Total Tree Fund Projects 56,248 992 - - - - 57,240 CIP Grant Street Projects Citywide Signal Upgrade II (924) (41) - - - (965) Saratoga Ave Sidewalk 9,218 - - 855 - - 8,363 Total CIP Grant Street Projects 8,294 (41) - 855 - - 7,397 CIP Grant Park & Trail Projects AB8939 Beverage Container Grant Funding 4,618 (4,618) - - - - - Joe's Trail at Saratoga / De Anza 12,809 - - - - - 12,809 Total CIP Grant Park & Trail Projects 17,427 (4,618) - - - - 12,809 Park In-Lieu Fees Projects Quarry Park Plan Implement 153,888 69,001 - 143,302 - - 79,587 Saratoga Village Creek Trail - Design - - - - 31,000 - 31,000 Saratoga Village Creek - Construction 19,000 - - - - - 19,000 Unallocated Park Fees 103,865 - - - - - 103,865 Total park In-Lieu Fees Projects 276,753 69,001 - 143,302 31,000 - 233,452 Gas Tax Fund Projects Annual Street Resurfacing 108,068 179,961 55,508 21,164 33,878 - 356,251 Prospect/Saratoga OBAG Improvement 544,825 (15,399) - 323 - - 529,103 Citywide Signal Upgrade II 99,769 (10) - - - - 99,759 Arroyo de Arguello Storm Drain 33,878 - - - - 33,878 - Quito Road & Paseo Olivos Storm Drain 40,000 - - - - - 40,000 OBAG Big Basin Way S/WCG 20,990 - - - - - 20,990 Quito Road Bridges 7,085 - - - - - 7,085 Total Gas Tax Fund Projects 854,615 164,552 55,508 21,488 33,878 33,878 1,053,188 Total CIP Funds 3,858,778 (454,270) 76,384 316,825 2,000,602 97,946 5,066,723 42 ATTACHMENT C CHANGE IN CASH BALANCE BY MONTH 43 ATTACHMENT D March June September December 1977 5.68 5.78 5.84 6.45 1978 6.97 7.35 7.86 8.32 1979 8.81 9.10 9.26 10.06 1980 11.11 11.54 10.01 10.47 1981 11.23 11.68 12.40 11.91 1982 11.82 11.99 11.74 10.71 1983 9.87 9.64 10.04 10.18 1984 10.32 10.88 11.53 11.41 1985 10.32 9.98 9.54 9.43 1986 9.09 8.39 7.81 7.48 1987 7.24 7.21 7.54 7.97 1988 8.01 7.87 8.20 8.45 1989 8.76 9.13 8.87 8.68 1990 8.52 8.50 8.39 8.27 1991 7.97 7.38 7.00 6.52 1992 5.87 5.45 4.97 4.67 1993 4.64 4.51 4.44 4.36 1994 4.25 4.45 4.96 5.37 1995 5.76 5.98 5.89 5.76 1996 5.62 5.52 5.57 5.58 1997 5.56 5.63 5.68 5.71 1998 5.70 5.66 5.64 5.46 1999 5.19 5.08 5.21 5.49 2000 5.80 6.18 6.47 6.52 2001 6.16 5.32 4.47 3.52 2002 2.96 2.75 2.63 2.31 2003 1.98 1.77 1.63 1.56 2004 1.47 1.44 1.67 2.00 2005 2.38 2.85 3.18 3.63 2006 4.03 4.53 4.93 5.11 2007 5.17 5.23 5.24 4.96 2008 4.18 3.11 2.77 2.54 2009 1.91 1.51 0.90 0.60 2010 0.56 0.56 0.51 0.46 2011 0.51 0.48 0.38 0.38 2012 0.38 0.36 0.35 0.32 2013 0.28 0.24 0.26 0.26 2014 0.24 0.22 0.24 0.25 2015 0.26 0.28 0.32 Quarterly Apportionment Rates Local Agency Investment Fund 44 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: Finance & Administrative Services PREPARED BY: Ann Xu, Accountant SUBJECT: Treasurer’s Report for the Month Ended November 30, 2015 RECOMMENDED ACTION: Review and accept the Treasurer’s Report for the month ended November 30, 2015. BACKGROUND: California government code section 41004 requires that the City Treasurer submit to the City Clerk and the legislative body a written report and accounting of all receipts, disbursements, and fund balances. The Municipal Code of the City of Saratoga, Article 2-20, Section 2-20.035 designates the City Manager as the City Treasurer. This report is prepared to fulfill this requirement. The following attachments provide various financial transaction data for the City of Saratoga’s Funds collectively as well as specifically for the City’s General (Operating) Fund, including an attachment from the State Treasurer’s Office of Quarterly LAIF rates from the 1st Quarter of 1977 to present. FISCAL STATEMENT: Cash and Investments Balance by Fund As of November 30, 2015, the City had $203,246 in cash deposit at Comerica bank, and $15,084,095 on deposit with LAIF. Council Policy on Working Capital Reserve Funds, adopted on April 20, 1994, states that: for cash flow purposes, to avoid occurrence of dry period financing, pooled cash from all funds should not be allowed to fall below $2,000,000. The total pooled cash balance as of November 30, 2015 is $15,287,341 and exceeds the minimum limit required. The following Fund Balance schedule represents actual funding available for all funds at the end of the monthly period. This amount differs from the above Cash Summary schedule as assets and liabilities are components of the fund balance. As illustrated in the summary below, Total Unrestricted Cash is adjusted by the addition of Total Assets less the amount of Total Liabilities to arrive at the Ending Fund Balance – which represents the actual amount of funds available. Unrestricted Cash Comerica Bank 203,246$ Deposit with LAIF 15,084,095$ Total Unrestricted Cash 15,287,341$ Cash Summary 45 Fund Balance Designations In accordance with Governmental Accounting Standards Board (GASB) Statement No. 54, Fund Balance Reporting and Governmental Fund Type Definitions, the components of fund balance are categorized as follows: “non-spendable fund balance”, resources that are inherently non-spendable from the vantage point of the current period; “restricted fund balance”, resources that are subject to enforceable legal restrictions; “committed fund balance”, resources whose use is constrained by limitations the government imposes upon itself through formal action at its highest level of decision making and remains binding unless removed in the same manner; “assigned fund balance”, resources that reflects a government’s intended use of resources, such intent would have to be established at either the highest level of decision making, by a body, or an official designated for that purpose; and “unassigned fund balance”, net resources in excess of what can properly be classified in one of the other four categories. Currently, the City’s fund balance reserves fall into one of the four spendable categories; restricted, committed, assigned, or unassigned fund balance. CONSEQUENCES OF NOT FOLLOWING RECOMMENDED ACTION The City would not be in compliance with Government Code Section 41004. ATTACHMENTS A – Change in Total Fund Balances by Fund under GASB 54 B – Change in Total Fund Balances by CIP Project C – Change in Cash Balance by Month D – Local Agency Investment Fund (LAIF) Quarterly Apportionment Rates + Total Unrestricted Cash 15,287,341$ Plus: Assets 729,890 Less: Liabilities (2,714,875) Ending Fund Balance 13,302,356$ Adjusting Cash to Ending Fund Balance 46 ATTACHMENT A CHANGES IN TOTAL FUND BALANCE UNDER GASB 54 Fund Description Fund Balance 7/1/15 Increase/ (Decrease) Jul-Oct Current Revenue Current Expenditure Transfer In Transfer Out Fund Balance 11/30/15 General Fund Restricted Fund Balances: Environmental Services Reserve 363,182 - - - - - 363,182 Committed Fund Balances: Hillside Stability Reserve 1,000,000 - - - - - 1,000,000 Assigned Fund Balances: Future Capital Replacement & Efficiency Project Reserve 1,777,896 - - - - 1,777,896 - Facility Reserve 900,000 - - - - - 900,000 Carryforwards Reserve 176,560 - - - - - 176,560 Unassigned Fund Balances:- Working Capital Reserve 2,007,545 - - - - - 2,007,545 Fiscal Stabilization Reserve 1,000,000 - - - - - 1,000,000 Development Services Reserve 713,891 - - - - 60,000 653,891 Compensated Absences Reserve 208,167 - - - - - 208,167 Other Unassigned Fund Balance Reserve (Pre YE distribution 1,659,490 (3,466,916) 1,630,573 1,133,733 - 64,760 (1,375,346) General Fund Total 9,806,731 (3,466,916) 1,630,573 1,133,733 - 1,902,656 4,933,999 Special Revenue Landscape/Lighting Districts 867,643 (145,646) 33,228 21,999 - - 733,227 Capital Project Street Projects 1,041,388 (261,257) 18,220 106,697 1,088,760 - 1,780,415 Park and Trail Projects 888,565 (424,392) - 4,652 328,068 64,068 723,521 Facility Projects 347,618 (109,163) 6,220 222 233,896 - 478,349 Administrative Projects 367,869 (19,648) 3,605 31,341 285,000 - 605,486 Tree Fund Projects 56,248 992 - - - - 57,240 Park In-Lieu Fees Projects 276,753 (74,301) - 75,688 31,000 - 157,764 CIP Grant Street Projects 8,294 (896) - 1,328 - - 6,070 CIP Grant Park & Trail Projects 17,427 (4,618) 8,397 - - - 21,206 Gas Tax Fund Projects 854,615 198,573 - 16,400 33,878 33,878 1,036,788 CIP Fund Total 3,858,778 (694,711) 36,443 236,328 2,000,602 97,946 4,866,838 Debt Service Library Bond 906,600 (689,720) 930 - - - 217,811 Internal Service Fund Liability/Risk Management 291,263 (40,127) - 14,123 - - 237,013 Workers Compensation 314,525 (428) - 2,583 - - 311,514 Office Support Fund 75,075 13,121 1,018 1,657 - - 87,557 Information Technology Services 260,322 65,080 - 33,487 - - 291,915 Equipment Maintenance 115,564 60,313 - 9,126 - - 166,751 Building Maintenance 268,326 177,705 - 55,980 - - 390,051 Equipment Replacement 649,498 67,967 - 972 - - 716,493 Technology Replacement 194,101 55,086 - - - - 249,187 Building FFE Replacement - 100,000 - - - - 100,000 - Total City 17,608,426 (4,498,275) 1,702,194 1,509,988 2,000,602 2,000,602 13,302,356 47 ATTACHMENT B FUND BALANCES BY CIP PROJECT CIP Funds/Projects Fund Balance 7/1/15 Increase/ (Decrease) Jul-Oct Current Revenue Current Expenditure Transfer In Transfer Out Fund Balance 11/30/15 Street Projects Annual Street Resurfacing - 24,474 18,220 (20,992) 64,760 - 128,447 Residential Street Construction 243,612 (175,226) - 12,460 300,000 - 355,925 Roadway Maintenance and Repairs - (49,617) - 74,351 375,000 - 251,032 EV Stations - - - - 25,000 - 25,000 Roadway Safety & Traffic Calming 27,114 (9,291) - - 50,000 - 67,822 Highway 9 Safety Project - Phase IV 121,019 - - - - - 121,019 Beaumont Traffic Circle - - - - 30,000 - 30,000 Village LED Streetlights 5,007 - - 172 - - 4,835 Annual Sidewalks Project 46,702 (48,470) - - 50,000 - 48,232 Annual Storm Drain Upgrade 9,352 (3,127) - 40,706 50,000 - 15,519 Village-Streetscape Improvements 25,059 - - - 50,000 - 75,059 Village Sidewalk Curb & Gutter Construction - Phase II 85,281 - - - - - 85,281 EL Camino Grande SD Pump 150,000 - - - - - 150,000 Saratoga Hills SD Pump - - - - 44,000 - 44,000 Storm Drain Capture Device 30,000 - - - - - 30,000 Wildcat Creek Outfall 40,000 - - - - - 40,000 Fourth Street Bridge 100,000 - - - - - 100,000 Quito Road Bridge Replacement Design 59,500 - - - - - 59,500 Bridge Maintenance & Repairs - - - - 50,000 - 50,000 Underground Project 98,744 - - - - - 98,744 Total Street Projects 1,041,388 (261,257) 18,220 106,697 1,088,760 - 1,780,415 Parks & Trails Projects Park/Trail Repairs 67,929 - - - - 64,068 3,861 Park Pathway Repairs - - - - 50,000 - 50,000 Sustainable Landscaping - - - 4,652 89,068 - 84,416 Hakone Garden Matching Funds 193,991 (59,010) - - - - 134,980 Hakone Garden Upper Moon House 125,000 - - - - - 125,000 Quarry Park Plan Implement 290,768 (361,622) - - 90,000 - 19,146 Quarry Park Row Acquisition 100,000 - - - - - 100,000 Joe's Trail at Saratoga/De Anza 33,997 - - - - - 33,997 Guava/Fredericksburg Entrance 45,880 - - - - - 45,880 Saratoga Village Creek Trail - Design 31,000 (3,760) - - 18,000 - 45,241 Saratoga Village Creek Trail - Construction - - - - 81,000 - 81,000 Total Parks & Trails Projects 888,565 (424,392) - 4,652 328,068 64,068 723,521 Facility Projects Facility Projects 43,500 (43,500) - - - - - Security Locks 53,007 - - - - - 53,007 City Hall Emergency Power Backup 325 (325) - - - - - Master Switch - Electrical Board 73,498 (56,391) - - - - 17,107 ENG/CDD Window Replacement - - - - 40,000 - 40,000 Civic Theater Improvements 87,882 (159) 6,220 222 - - 93,721 Civic Theater Master Plan Improvements 64,900 (2,793) - - - - 62,108 Theater Boiler Replacement - - - - 90,000 - 90,000 Theater Rooftop Duct Work - - - - 90,000 - 90,000 Pre-School Playground Structure 10,458 (5,996) - - - - 4,462 SPCC Furniture & Fixtures - - - - 13,896 - 13,896 McWilliams House Improvements - Phase II 3,578 - - - - - 3,578 Library Building Exterior Maintenance Projects 10,470 - - - - - 10,470 Total Facility Projects 347,618 (109,163) 6,220 222 233,896 - 478,349 48 ATTACHMENT B (Cont.) FUND BALANCES BY CIP PROJECT CIP Funds/Pro jects Fund Balance 7/1/15 Increase/ (Decrease) Jul-Oct Current Revenue Current Expenditure Transfer In Transfer Out Fund Balance 11/30/15 Administrative Projects Financial System Upgrade 3,534 - - - - - 3,534 COMB Document Imaging Project 57,894 (7,083) - 776 - - 50,035 City Website/Intranet - - - 1,478 75,000 - 73,523 Development Technology 22,928 14,786 3,605 17,368 - - 23,952 Trak-It Software Upgrade - - - - 60,000 - 60,000 LLD Initiation Match Program 49,000 - - - - - 49,000 Horseshoe Beautification 25,000 - - - - - 25,000 General Plan Update 100,000 - - - - - 100,000 Village Façade Program 20,321 - - - - - 20,321 Village Specific Plan Update - (3,330) - 10,724 100,000 - 85,946 Wildfire Protection Plan 25,000 - - - - - 25,000 Risk Management Project Funding 64,192 (24,020) - 995 50,000 - 89,176 Total Administrative Projects 367,869 (19,648) 3,605 31,341 285,000 - 605,486 Tree Fund Projects Citywide Tree Planting Program 33,248 867 - - - - 34,115 Tree Dedication Program 21,250 125 - - - - 21,375 SMSCF Tree Donation Program 1,750 - - - - - 1,750 Total Tree Fund Projects 56,248 992 - - - - 57,240 CIP Grant Street Projects Citywide Signal Upgrade II (924) (41) - - - (965) Village LED Streetlights - - - 1,328 - - (1,328) Saratoga Ave Sidewalk 9,218 (855) - - - - 8,363 Total CIP Grant Street Projects 8,294 (896) - 1,328 - - 6,070 CIP Grant Park & Trail Projects AB8939 Beverage Container Grant Funding 4,618 (4,618) 8,397 - - - 8,397 Joe's Trail at Saratoga / De Anza 12,809 - - - - - 12,809 Total CIP Grant Park & Trail Projects 17,427 (4,618) 8,397 - - - 21,206 Park In-Lieu Fees Projects Quarry Park Plan Implement 153,888 (74,301) - 75,688 - - 3,899 Saratoga Village Creek Trail - Design - - - - 31,000 - 31,000 Saratoga Village Creek - Construction 19,000 - - - - - 19,000 Unallocated Park Fees 103,865 - - - - - 103,865 Total park In-Lieu Fees Projects 276,753 (74,301) - 75,688 31,000 - 157,764 Gas Tax Fund Projects Annual Street Resurfacing 108,068 214,306 - - 33,878 - 356,251 Prospect/Saratoga OBAG Improvement 544,825 (15,722) - 16,400 - - 512,703 Citywide Signal Upgrade II 99,769 (10) - - - - 99,759 Arroyo de Arguello Storm Drain 33,878 - - - - 33,878 - Quito Road & Paseo Olivos Storm Drain 40,000 - - - - - 40,000 OBAG Big Basin Way S/WCG 20,990 - - - - - 20,990 Quito Road Bridges 7,085 - - - - - 7,085 Total Gas Tax Fund Projects 854,615 198,573 - 16,400 33,878 33,878 1,036,788 Total CIP Funds 3,858,778 (694,711) 36,443 236,328 2,000,602 97,946 4,866,838 49 ATTACHMENT C CHANGE IN CASH BALANCE BY MONTH 50 ATTACHMENT D March June September December 1977 5.68 5.78 5.84 6.45 1978 6.97 7.35 7.86 8.32 1979 8.81 9.10 9.26 10.06 1980 11.11 11.54 10.01 10.47 1981 11.23 11.68 12.40 11.91 1982 11.82 11.99 11.74 10.71 1983 9.87 9.64 10.04 10.18 1984 10.32 10.88 11.53 11.41 1985 10.32 9.98 9.54 9.43 1986 9.09 8.39 7.81 7.48 1987 7.24 7.21 7.54 7.97 1988 8.01 7.87 8.20 8.45 1989 8.76 9.13 8.87 8.68 1990 8.52 8.50 8.39 8.27 1991 7.97 7.38 7.00 6.52 1992 5.87 5.45 4.97 4.67 1993 4.64 4.51 4.44 4.36 1994 4.25 4.45 4.96 5.37 1995 5.76 5.98 5.89 5.76 1996 5.62 5.52 5.57 5.58 1997 5.56 5.63 5.68 5.71 1998 5.70 5.66 5.64 5.46 1999 5.19 5.08 5.21 5.49 2000 5.80 6.18 6.47 6.52 2001 6.16 5.32 4.47 3.52 2002 2.96 2.75 2.63 2.31 2003 1.98 1.77 1.63 1.56 2004 1.47 1.44 1.67 2.00 2005 2.38 2.85 3.18 3.63 2006 4.03 4.53 4.93 5.11 2007 5.17 5.23 5.24 4.96 2008 4.18 3.11 2.77 2.54 2009 1.91 1.51 0.90 0.60 2010 0.56 0.56 0.51 0.46 2011 0.51 0.48 0.38 0.38 2012 0.38 0.36 0.35 0.32 2013 0.28 0.24 0.26 0.26 2014 0.24 0.22 0.24 0.25 2015 0.26 0.28 0.32 Quarterly Apportionment Rates Local Agency Investment Fund 51 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: City Manager’s Office PREPARED BY: Debbie Bretschneider, Deputy City Clerk SUBJECT: Resolution Authorizing Final Disposition of Certain City Records RECOMMENDED ACTION: Adopt resolution authorizing final disposition of certain city records. REPORT SUMMARY: On June 17, 2015, the City Council approved a new Records Retention Schedule. In accordance with the schedule, staff and the City Attorney review archived documents to determine those that are nonessential and can, therefore, be shredded. In order to comply with State law, processing expired records for destruction is a multi-step process: 1. Staff in each department identifies records for which the retention period has expired in accordance with the approved records retention schedule. Each box is looked through to make sure it does not include records that must be retained. 2. Department directors review and approve the list of records to be destroyed in their departments. 3. The City Clerk and City Attorney review and approve a combined list of all expired records. 4. The list of records is presented to the City Council along with a resolution authorizing the shredding of listed documents. Records may not be shredded without the authorization of the City Council. At this time, staff has identified 38 boxes of expired records and is requesting authorization from the Council to proceed with shredding the documents. FOLLOW UP ACTION: Consistent with the City’s standard policy, the records will be held for seven days for review pursuant to the Public Records Act. If no request for review is submitted, they will be promptly destroyed. If a request for review is submitted, the records will be destroyed between 20 and 30 days after they have been made available for review. 52 ATTACHMENTS: Attachment 1 -Resolution Authorizing the Final Disposition of Certain City Records Attachment 2 -Exhibit A: List of Records Proposed for Final Disposition 556489.1 53 RESOLUTION NO. 16- A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SARATOGA AUTHORIZING THE FINAL DISPOSITION OF CERTAIN CITY RECORDS WHEREAS, Government Code Section 34090 et seq. authorizes City department heads to destroy certain records, documents, instruments, books or paper after the same are no longer required with the approval of the legislative body by resolution and the written consent of the City Attorney. NOW, THEREFORE, the City Council of the City of Saratoga hereby resolves as follows: 1.Department heads are hereby authorized to have destroyed those certain records, documents, instruments, books or paper under their charge as described in Exhibit ‘A. 2.The records, documents, emails, instruments, books or paper described in Exhibit ‘A shall be held for seven days for review pursuant to the Public Records Act prior to destruction. If no request for review is submitted within that time, they shall be promptly destroyed. If a request for review is submitted, the records shall be destroyed not less than twenty days and not more than thirty days after the records have been made available for review. The above and foregoing resolution was passed and adopted at a regular meeting of the Saratoga City Council held on the 20th day of January, 2016 by the following vote: AYES: NOES: ABSENT: ABSTAIN: _____________________________ E. Manny Cappello, Mayor ATTEST: ____________________________ Crystal Bothelio, City Clerk CITY ATTORNEY CONSENT TO DESTRUCTION OF THE RECORDS, DOCUMENTS, INSTRUMENTS, BOOKS OR PAPER DESCRIBED IN EXHIBIT ‘A.: __________________________ Richard Taylor City Attorney 54 January 2016 destruction list Department Description Destruction date Retention CMO1 Ctclerk Activity Guides 1974, Grand Jury report 2004, 2005, Terminated contracts 1999, Correspondance 2011-2013 1/1/2016 Current year +10, Current+ 2 after scanning CMO2 Ctclerk Case records, Informal 1990-93, 1979 1/1/2011 Current year+7 CMO3 Ctclerk Correspondance 1990-1995, Legal ads 2002-2012, Public Reco 1/1/2016 Current year+2, Current year+4, Closed+2 CMO4 Ctclerk Public Records Request 2009-2013 1/1/2016 Closed+2 CMO5 Ctclerk Public Records Request 2009-2013 1/1/2016 Closed+2 CMO7 Ctclerk Commissioner Applications -Not Selected 1999-2012 Comessioner Applications -Terminated 1996-2007 1/1/2015 Closed+2, Term+5 19A Claims 2001-2004 1/1/2011 Closed+5 398 Recreation ABAG claim forms 2010 12-31-2015 Superseded+5 399 Recreation ABAG claim forms 2010 12-31-2015 Superseded+5 403 Recreation Teacher payments 01-01-2011 thru 12-31-2011 12/31/2015 Current year +4 406 Recreation Registration Forms 2013 12/31/2015 Current year+2 Finance Employee Timesheets, Record Dates 07/06 TO 06/07 12-31-2015 Audit + 6 628 Finance Employee time sheets FY 08/09 12-31-2015 Audit + 6 677 Finance FY 2010-2011 Cash receipts 7/1/2010-8/31/2010 12/31/2015 Audit + 4 678 Finance FY 2010-2011 Cash receipts 9/1/2010-10/31/2010 12/31/2015 Audit + 4 679 Finance FY 2010-2011 Cash receipts 11/1/2010- 12/31/2010 12/31/2015 Audit + 4 680 Finance FY 2010-2011 Cash receipts 1/1/2011- 2/28/2011 12/31/2015 Audit + 4 681 Finance FY 2010-2011 Cash receipts 3-1-2011-4-30-2011 12/31/2015 Audit + 4 682 Finance FY 2010-2011 Cash receipts 5/1/2011- 6/30/2011 12/31/2015 Audit + 4 684 Finance Accounts Payable (AP)FY 2010-11 Weekly check run 7/8/10- 9/8/10 (check register)12/31/2015 Audit + 4 685 Finance AP -FY 2010/11 weekly check run 10/28/10- 12/16/10 (check register)12/31/2015 Audit + 4 686 Finance AP -FY 2010/11 weekly check run 1/28/11 - 3/3/11 (check register)12/31/2015 Audit + 4 55 687 Finance AP- FY 2010/11 Weekly check run 3/11/11 - 4/22/11 (check register)12/31/2015 Audit + 4 688 Finance AP -FY 2010/11 Weekly Check run 12/22/10 - 1/14/11 (check register)12/31/2015 Audit + 4 689 Finance AP - FY 2010/11 Weekly Check run 9/16/10 - 10/21/10 (current year)12/31/2015 Audit + 4 690 Finance AP -FY 2010/11 Weekly Check run 4/28/11 - 6/16/11 (Current year)12/31/2015 Audit + 4 691 Finance AP - FY 2010/11 Weekly Check run 6/23/11 - 8/9/11 (PER. 13) (Current year)12/31/2015 Audit + 4 693 Finance AP FY 2009-10 Closed purchase orders 12-31-2015 Audit + 4 724 Finance A-Z Cash Receipt backup FY 2010-11 12/31/2015 Audit + 4 725 finance Cash Receipts (parking citations paid by residents) FY 2010-1112/31/2015 Audit + 4 734 finance Accounts Receivable FY 2010-11 and False Alarm cards Calendar Year 2011 12/31/2015 Audit + 4 784 Finance FY 2008/09 Cash Receipts 12/31/2013 Audit +4 785 Finance CY 2009 Business license renewal reports 12/31/2013 Term +4 786 Finance CY 2010 (Jan-May) business license renewable reports 12/31/2014 Term+4 787 Finance CY2010 (June-Dec) business license renwal reports 12/31/2014 Term+4 788 Finance CY 2011 business license renewal reports 12/31/2015 Term+4 789 Finance CY 2009 False Alarm cards 1/1/09 - 12/31/2009 12/31/2013 Audit+4 790 Finance CY 2010 False Alarm cards 12/31/2014 Audit+4 56 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: Recreation and Facilities PREPARED BY: Michael A. Taylor, Director SUBJECT: Approval of Contract with NBBM for Janitorial Services RECOMMENDED ACTION: Staff recommends that Council approve a contract with NBBM Services for janitorial services of City facilities in the amount of $67,000. BACKGROUND: The City of Saratoga Facilities Department has relied upon contract janitorial services since the departure of one of the two Building Maintenance workers last year. Proposals and bids were solicited from twelve (12) providers (Attachment A) and NBBM provided the lowest bid (Attachment B) for services. Staff therefore recommends that Council approve the attached contract (Attachment C) and authorize the City Manager to execute the same. The contract is valid through June 30, 2017 for an amount not to exceed $67,000. FISCAL STATEMENT: Funding for this contract is included in the adopted Facilities Building Maintenance operating budget. ATTACHMENTS: Attachment A - Bid Proposal List Attachment B - NBBM Bid Proposal Attachment C - NBBM Service Contract Janitorial Company Bidding Information Listed below are the results from a Janitorial Company service survey to find a Janitorial Company to provide backfill janitorial service for the City of Saratoga. The Janitorial Companies were called and asked if they provided afterhours janitorial services, what their minimum amount of daily hour’s requirement was and what their hourly rate is for this type of service. 1.West Coast Cleaning Systems, Contacted 12/1, 12/8 no information submitted 2.United Building Maintenance, Contacted 12/1, 12/3 no staff to do this type of service 3.Jan Pro of Silicon Valley, Contacted 12/1, 12/8 no information submitted 4.Moreno and Associates, Contacted 12/1, 12/2 stated 4 hour minimum at $27.50 an hour 5.Service by Medallion, Contacted 12/1, 12/7 stated 4 hour minimum but no other information submitted 6.Facility Masters, Contacted 12/1, 12/2 stated 4 hour minimum at $22.00 an hour 7.Flagship Facility Services, Contacted 12/1, 12/8 no information submitted 8.Green City Office Cleaning, Contacted 12/1, 12/1 stated 2 hour minimum at $45.00 an hour 9.Action Maintenance System, Contacted 12/1, 12/1 stated 8 hour minimum at $32.50 an hour 10.NBBM Services, Contacted 12/1, 12/3 stated 5 hour minimum at $19.00 an hour 11.California Commercial Cleaning, Contacted 12/1, 12/8 no information submitted 12.San Jose Building Maintenance, Contacted 12/1, 12/2 stated 4 hour minimum at $25.00 an hour 57 December 8, 2015 Thomas Scott City of Saratoga, Facilities Maintenance Manager 13777 Fruitvale Avenue Saratoga, California 95070 Re: Janitorial services for the City of Saratoga Mr. Scott, Our hourly rate to perform janitorial service and additional help for the City of Saratoga facilities will be $19.00 per man hour. On behalf of NBBM, we wish to express our appreciation for the opportunity to submit our proposal. We look forward to a long lasting business relationship. There must be a minimum of 5 hours of work before we are able to send out a man. Thank you for requesting this proposal from us, if you find it acceptable please sign and email back the signed page. Sincerely, Accepted by R J. Gonzales Date / / 58 59 60 61 62 63 64 65 66 67 68 69 70 71 72 73 74 75 76 SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:City Manager’s Office PREPARED BY:James Lindsay, City Manager SUBJECT:Resolution Updating Unrepresented Employee’s Compensation and Terms of Employment RECOMMENDED ACTION: Adopt the resolution approving compensation and terms of employment for Unrepresented Employees. BACKGROUND: On December 17, 2015, the City Manager’s Office received a Decertification Petition from the Saratoga Management Organization (SMO) with Proof of Support that was signed by all four Department Director members stating that SMO members no longer desire to be represented by the incumbent employee organization (SMO). SMO has been an Exclusively Recognized Employee Organization representing the four Department Directors. The petition was filed in conformance with the City’s Personnel Rules and Policies Article 22, Section 3, Subdivision 6 - Procedure for Decertification of Exclusively Recognized Employee Organization. A secret ballot election has been initiated for the members to vote on the decertification. The results of the election will be provided as a supplemental attachment prior to the City Council meeting. If a majority of members vote in favor of decertification, SMO will be decertified and no longer exist and the four employees will become unrepresented. If SMO’s members vote to decertify SMO, I am submitting to Council a Resolution with modifications to the Compensation and Terms of Employment for Unrepresented Classifications to include the four Department Directors and a new section with benefits exclusively for at-will employees. The Directors are at-will employees that serve at the pleasure of the City Manager. ATTACHMENTS: A.SMO Decertification Petition B.Draft Resolution 77 78 79 RESOLUTION NO. ____ A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SARATOGA APPROVING COMPENSATION AND TERMS OF EMPLOYMENT FOR UNREPRESENTED EMPLOYEES WHEREAS, certain City job classifications are unrepresented, which means incumbents do not engage in collective bargaining with the City on matters related to wages, benefits and other terms and conditions of employment; and WHEREAS, Unrepresented Employees are those employees in unpresented job classifications who are regular, benefited full-time employees, after successfully completing the City's mandatory 12- month probationary period (if applicable); and WHEREAS, Unrepresented Employees are subject to the City's Personnel Rules and Policies adopted by the City Council and are subject to the terms in this Resolution (except as modified by subsequent personnel rules and policies and resolutions, if any, applicable to unrepresented job classifications); and WHEREAS, this Council finds that the compensation and terms of employment attached (Exhibit A) to this Resolution are fair and proper and in the best interest of the City; and NOW, THEREFORE BE IT RESOLVED, by the City Council of the City of Saratoga the compensation and terms of employment attached to said Resolution for Unrepresented Employees is hereby adopted, becomes effective on January 20, 2016, and supersede the terms in Resolution No. 15- 037. The above and foregoing resolution was passed and adopted by the Saratoga City Council at a regular meeting held on the 20th day of January 2016, by the following vote: AYES: NOES: ABSENT: ABSTAIN: ___________________________ E. Manny Cappello, Mayor ATTEST: _____________________________DATE:________________ Crystal Bothelio, City Clerk CITY OF SARATOGA 80 Adopted January 20, 2016 UNREPRESENTED CLASSIFICATIONS COMPENSATION AND TERMS OF EMPLOYMENT I.INTRODUCTION This Resolution establishes the compensation and other terms for benefited regular full-time unrepresented job classifications that are not included in a collective bargaining agreement, memorandum of understanding, or employment contract. Unrepresented classifications are subject to the City's Personnel Rules and Policies adopted by the City Council and are subject to the terms in this Resolution (except as modified by subsequent personnel rules and policies and resolutions, if any, applicable to such an unrepresented, regular, full-time employee). The terms in this document, once adopted by the City Council, supersede the terms in the 2015 Resolution (Resolution No. 15-037) effective as of January 20, 2016 , or on the effective date noted for each term. II.UNREPRESENTED JOB CLASSIFICATIONS Community Development Director Finance and Administrative Services Director Public Works Director Recreation and Facilities Director City Clerk / Assistant to the City Manager Finance Manager Human Resources Manager Parks Division Manager Streets and Fleets Division Manager Human Resources Technician Any other job classification determined not appropriate to be included in a represented bargaining unit. III.COST OF LIVING ADJUSTMENT Each employee shall receive an annual cost-of-living adjustment of no less than one percent (1.0%) and no greater than two and one-half percent (2.5%) as based upon the annual average for the 12 month period of January 1 to December 31 of the U.S. Department of Labor, Bureau of Labor Statistics, "All Urban Consumers (CPI-U)" for the "San FranciscoOakland-San Jose" region. If the annual average falls below one percent (1.0%), each employee shall nevertheless receive a minimum one percent (1.0%) cost-of-living adjustment; if the above Index increases above two and one-half percent (2.5%), each classification shall nevertheless receive a maximum two and one-half percent (2.5%) cost-of-living adjustment. 81 Adopted January 20, 2016 IV.EMPLOYEE BENEFITS A.Health and Dental Premium Contributions Effective July 1, 2015 through December 31, 2015, for employees hired prior to 7/1/2011, the City pays the monthly premium, at the tier of coverage selected by the employee, up to a maximum of the highest cost HMO. Effective July 1, 2015 through December 31, 2015, for employees hired on or after 7/1/2011, the City contribution towards the total monthly health plan cost is the following: $600 for Employee Only, $1,200 for Employee Plus One, and $1,500 for Employee Plus Two (Family). Effective January 1, 2016, the City will provide a monthly health insurance contribution for each employee’s selected level of coverage as follows in the chart below: Employee Employee Plus One Employee Plus Two (Family) $800.00 $1,600.00 $2,080.00 The City’s monthly health insurance contribution will be adjusted annually as follows. 1.Prior to the beginning of the CalPERS open enrollment period, the City will compare the average monthly cost of all plans offered in the next calendar year for each level of coverage (Employee, Employee + 1, and Employee +2) with the current year average monthly costs for each level of coverage. The average will be calculated by adding the cost for each plan at the same level of coverage and then dividing by the number of plans. 2.If the average cost for a level of coverage in the next calendar year will exceed the average cost for the same level in the current year, then the City’s monthly contribution for that level of coverage will be increased by 50% of the difference of the two yearly averages. 3.If the average cost for a level of coverage in the next calendar year is below the average cost for the same level in the current year, then the City monthly contribution for that level of coverage will not change. The adjusted City contribution for each level of coverage for the next calendar year will be provided to the employees prior to the beginning of the open enrollment period and become effective on January 1 of each year. Examples: (1)The 2016 (base year) City monthly contribution for the family level of coverage is $2,080 and the average cost of all plans at the family level offered in 2017 will be $2,366. The City’s monthly contribution will be increased to $2,168 ($2,366 - $2,190 = $176, 50% of the $176 difference = an increase of $88). The employee would pay the balance of $88 for the plan selected. 82 Adopted January 20, 2016 (2)The 2017 average monthly contribution for the family level of coverage is $2,168 and the average cost of all plans at the family level offered in 2018 will be $2,554. The City’s monthly contribution for 2018 would be increased from $2,168 (the 2017 rate) to $2,262 ($2,554 - $2,366 = $188, 50% of the $188 difference = an increase of $94). The employee would pay the balance of $94 for the plan selected. If an employee selects a health insurance plan with a monthly premium above the City contribution, the employee will pay the amount above the City contribution as a pre- tax payroll deduction. The CITY contributes 100% of the dental premium for regular, full-time employees. B.Health and Dental - In-Lieu Payments An employee who completes and submits required documents (1) to prove that the employee has other health insurance coverage and (2) to waive City-provided health insurance coverage will receive a payment per month of $350.00 as additional taxable wages. The employee must complete and submit any required documents and provide proof of other health insurance coverage during open enrollment (in or around October) to be eligible for the cash-in-lieu payment beginning the following January 1. Only qualifying events as defined by law allow employees to make a change to their health, dental, and/or inlieu enrollment elections during the year (outside of the annual open enrollment period). Any employee who declines to accept coverage in the Dental Plan, evidenced by signing a waiver form, shall receive a monthly in-lieu payment of $25.00. V.PTO CASH-OUT OPTION A PTO Cash-Out Option will not be made other than at the time of termination, except for the optional PTO cash-out plan described as follows: If an employee has used the required minimum of 80 accrued hours of PTO in the prior fiscal year, the employee is eligible to cash out up to a maximum of 200 accrued hours of PTO per fiscal year on approximately September 1 and/or March 1. An employee must maintain a minimum balance of 200 hours of accrued PTO after the cash out. VI.ADMINISTRATIVE LEAVE Administrative Leave is compensated time off given to regular, full-time exempt employees of the CITY. This leave shall be taken in a manner consistent with Paid Time Off (PTO). Use of administrative leave is a privilege and is provided in recognition that CITY projects often require employees to devote whatever hours are necessary, 83 Adopted January 20, 2016 irrespective of a regular scheduled workweek, to fulfill the obligations of the job. Sixty- five (65) hours of Administrative Leave is granted to the following exempt employees: Community Development Director Finance and Administrative Services Director Public Works Director Recreation and Facilities Director City Clerk / Assistant to the City Manager Finance Manager Human Resources Manager Parks Division Manager Streets and Fleets Division Manager Administrative leave cannot be carried over from year to year, and must be used by June 30th of the fiscal year in which it was provided. Administrative Leave must be exhausted prior to using PTO. VII.RETIREMENT (PERS) The CITY is a contracting agency of the California Public Employees Retirement System (PERS). Regular employees become members immediately upon employment and become vested after five years of full-time service. Tier 1 : CalPERS Retirement Plan of 2%@55 for Employees Hired Before July 1, 2011 : The CITY, through its contract with PERS, provides for retirement benefits for any employee hired before July 1, 2011 as defined by the 2%@55 retirement plan formula (contract effective date: September 1, 1999). The City’s 2%@55 contract with PERS includes Government Code 20042 – the final compensation is the average full-time monthly pay rate for the highest 12 consecutive months. As of July 1, 2011, each employee covered by the 2%@55 retirement plan formula will pay 7% of the employee’s compensation on a pre-tax basis for the employee’s 7% fixed share of the CalPERS defined benefit retirement program. Tier 2 : CalPERS Retirement Plan of 2%@60 for Employees Hired July 1, 2011 Through December 31, 2012: Each employee covered by the 2%@60 plan will pay 7% of the employee’s compensation on a pre-tax basis. New Hire CalPERS Retirement Plan For Employee Hired January 1, 2013 and After : Any employee hired on or after January 1, 2013, who does not meet the exceptions as specified in state law to be a “classic” member of PERS, will receive the following 3rd tier retirement option: 84 Adopted January 20, 2016 a)A retirement plan of 2% at 62 as required by state law (PEPRA). b)Each employee will pay on a pre-tax basis 100% of the employee’s contribution as determined by PERS toward the CalPERS 2%@62 retirement plan. An employee hired after January 1, 2013 who meets an exception under state law to be a “classic” member of PERS will receive the second tier plan of 2% at 60 noted above. VIII.PERFORMANCE INCENTIVE COMPENSATION Employees hired prior to July 1, 2011 who have remained at Step 5 for five (5) years may be eligible for an additional five percent (5%) of pay following receipt of a cumulative rating of meets expectations or greater during the anniversary employee performance evaluation. Five (5) years after meeting the criteria for the initial performance incentive compensation described above, a qualified employee -- that is an employee who has remained at five percent (5%) above the top of his/her same salary range -- may be eligible for an additional salary increase of five percent (5%), for a maximum of 10% above Step 5 following receipt of a cumulative rating of meets expectations or greater during the anniversary employee performance evaluation. IX.WORKING CONDITIONS The City operates on a 9/80 work schedule determined by the City Manager where a full- time work week, constitutes forty (40) hours within seven consecutive 24 hour days, also defined as one hundred sixty-eight (168) hours. Employees on a 9/80 schedule are scheduled to work 8 nine hour days, 1 eight hour day, and have one day off every two weeks. An employee's workweek begins in the middle of the employee's 8 hour day and the employee's day off is on the same day of the week in the following week. For example, the standard 9/80 work schedule is as follows: Sunday Monday Tuesday Wednesday Thursday Friday Saturday 4 (end) off 9 9 9 9 4 (start)off off (end) off 9 9 9 9 off (start)off 4 (end) off 9 9 9 9 4 (start)off off (end) off 9 9 9 9 off (start)off 85 Adopted January 20, 2016 The City Manager has discretion to require Unrepresented employees to work a schedule different from the standard 9/80 schedule including a schedule that is not 9/80. Fridays when the City is not open for business are referenced as "off-Fridays." The work period (pay period) is the period encompassing two consecutive workweeks. A holiday furlough will exist whereby the CITY operations are closed from December 24 through January 1 of every year. Two furlough days shall be compensated as a regular day’s salary. To be paid for a furlough day, an employee must be on paid status the week of the furlough with the City. All part-time employees and employees on short-term disability shall receive furlough pay on a pro-rata basis. For any remaining furlough days, employees shall utilize their available balances (earned paid time off or earned compensatory time), if applicable. Employees that utilize unpaid leave due to an insufficient leave balance shall maintain regular benefit status. Employees may not utilize unpaid leave prior to exhausting their available balances, except with prior written authorization signed by the City Manager. X.AT-WILL EMPLOYEE BENEFITS The following positions are at-will and serve at the pleasure of the City Manager: Community Development Director Finance and Administrative Services Director Public Works Director Recreation and Facilities Director A.Severance Should the City Manager choose to terminate an at-will employee, the following severance provisions apply and will be made available to the employee if the separated employees signs and agrees to be bound by a written general release agreeing not to sue and waiving claims and recovery against the City and all City representatives and agents. Starting on the one-year anniversary of the date of hire, employee shall be eligible for a general release agreement with (A) a severance payment equal to three (3) month’s salary; and (B) Health Insurance and Dental Insurance benefits specified in this agreement for a three (3) month period after termination. The severance payment and continuation of benefits listed above shall be increased by one (1) month for each year on the employee’s anniversary date up to a maximum of six (6) months’ severance pay and benefits. At the discretion of the employee whose employment has been terminated, the severance payment shall be paid either in a lump sum, or in bi-weekly payments, beginning within ten (10) days of the effective date of termination or within ten (10) days of the effective date of the signed general release, whichever is later. If an employee selects bi-weekly payments, the employee may later choose to receive a lump sum payment for the balance of the monthly severance payments. The change from bi-weekly payments to a lump sum payment for the balance will be processed as soon as reasonably feasible and by no later than two 86 Adopted January 20, 2016 weeks after the employee chooses to change to a lump sum payment for the balance. The severance payment shall be based on the employee’s then monthly salary. Severance benefits will be provided as follows: Health Insurance : The employee must enroll in COBRA, directly through their existing health plan provider, for extended health insurance. The employee must pay the health insurance premium directly to his/her provider and submit a copy of the premium invoice and proof of payment to the City for reimbursement. Dental Insurance : The City is able to directly enroll the employee in COBRA, through the City’s carrier, for extended dental insurance. The employee must contact the Human Resources Division and complete any requested documents to activate acceptance of COBRA for dental insurance. The Human Resources Division will provide to the employee a letter detailing all of the above instructions, and providing the necessary paperwork in a timely fashion, sufficient to ensure that the employee does not become ineligible for continued coverage. B.Deferred Compensation or Alternative and In-Lieu of Option The City will contribute $250.00 per month, on behalf of each at-will employee, to an account with the City-provided IRS Section 457 deferred compensation plan. Alternatively and in-lieu of the City contribution to a deferred compensation account of $250.00 per month, each employee may elect to instead receive the $250.00 per month (or a portion thereof), in taxable wages if that member informs the Human Resources Division in writing during open enrollment (in or around October) to be eligible for the cash-in-lieu of the City contribution to a deferred compensation account of $250 per month beginning the following January 1. C.Car Allowance Each at-will employee shall receive a monthly $275.00 car allowance. 87 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: City Manager’s Office PREPARED BY: Crystal Bothelio, City Clerk/Assistant to the City Manager SUBJECT: Library Commission Meeting Schedule RECOMMENDED ACTION: Adopt resolution amending the Library Commission meeting schedule. BACKGROUND: Currently, the Library Commission holds its regular meeting son the fourth Wednesday of every other month (even numbered months) at 4:00 p.m. at the Saratoga Library. The Library Commission has requested that the schedule be updated to encourage public attendance at meetings. The proposed meeting schedule is 7:00 p.m. on the fourth Tuesday of every other month (even numbered months). ATTACHMENTS: Attachment A – Resolution Amending the Library Commission Schedule RESOLUTION 16- A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SARATOGA AMENDING THE SARATOGA LIBRARY COMMISSION REGULAR MEETING SCHEDULE WHEREAS, the Saratoga Library Commission provides counsel and recommendations on library policies, budgets, plans, and procedures to the City Council, City staff, the Santa Clara County Library, and Saratoga Librarian; and WHEREAS, the Saratoga Library Commission currently meets on the fourth Wednesday of every other month (during even numbered months) at 4:00 p.m. at Saratoga Library; and WHEREAS, the Saratoga Library Commission will now hold its regular meetings on the fourth Tuesday of every other month (during even numbered months) at 7:00 p.m. at Saratoga Library; NOW, THEREFORE BE IT RESOLVED, that the City Council of the City of Saratoga does hereby amend the Saratoga Library Commission regular meeting schedule. The above and foregoing resolution was passed and adopted at a regular meeting of the Saratoga City Council held on the 20th day of January 2016 by the following vote: NOES: ABSENT: ABSTAIN: E. Manny Cappello, Mayor ATTEST: DATE: Crystal Bothelio, City Clerk 88 SARATOGA CITY COUNCIL MEETING DATE: January 20, 2016 DEPARTMENT: Administrative Services Department PREPARED BY: Mary Furey, Administrative Services Director SUBJECT: Consider actions related to the formation of a Community Choice Energy Program RECOMMENDATIONS: 1. Receive report on the Draft Silicon Valley Community Choice Energy Technical Study. 2. Conduct a Public Hearing and introduce and waive the first reading of the attached Ordinance to authorize the implementation of a Community Choice Energy Program and find that the project is exempt from CEQA pursuant to CEQA Guidelines 15378(a), 15061(b)(3), and 15308 . BACKGROUND Community Choice Energy (CCE) is a process authorized by California law that enables cities to pool customer electricity demand within their jurisdiction to directly procure or invest in electric power supplies on behalf of the residents and businesses in their communities. CCE is garnering substantial interest among California communities for the opportunity to accelerate the shift to renewable and low greenhouse gas (GHG) emitting energy sources in support of climate action objectives, and its potential to provide greener power at currently competitive rates. While electric supply is handled by the CCE program, the electricity grid and customer service would remain with the incumbent utility, or PG&E in Santa Clara County. Two operating multi-jurisdictional CCE programs (Marin and Sonoma counties) and a sole entity CCE program (City of Lancaster) provide useful benchmarks for program evaluation, development, and operation. Initially, the Cities of Sunnyvale, Cupertino, Mountain View and the County of Santa Clara formed a partnership to assess and potentially develop a multi-jurisdictional CCE program. This study included four components: 1) Interest of other communities in forming a South Bay CCE program; 2) Benefits of forming a CCE program, including the potential to advance other strategies within the CAP; 3) Costs and risks to forming a program; and 4) Framework to guide the formation of a CCE program. The initial Assessment Report was completed in May 2015 and concluded that market and program conditions were favorable to conduct a detailed Technical Feasibility Study. REPORT DISCUSSION Partnership The Technical study began in July 2015, in conjunction with the four agencies expanding the partnership to include eight additional communities in Santa Clara County who were potentially interested in participating in a CCE program. These eight communities; Campbell, Gilroy, Los Altos, Los Altos Hills, Los Gatos, Monte Sereno, 89 Morgan Hill, and Saratoga all authorized requests for PG&E to provide detailed electrical data for their jurisdictions to incorporate into the Technical Study. The Draft Technical Study (Attachment 1) released in November 2015, concluded that a program that provides greener power for rates at or below those of PG&E is viable. The report provided detailed analysis based on existing program performance and market conditions, inclusive of potential program risks and an overview of the resource needs and critical steps to launching a successful program. Of further note, interest in the CCE model is spreading throughout California, with more than 20 communities now evaluating and/or pursuing CCE, including San Mateo County, Alameda County, and a collaboration among Monterey, Santa Cruz, and San Benito Counties. Technical Study Findings The Partnership hired Pacific Energy Advisors (PEA) to complete a quantitative evaluation of the viability of a CCE program for Silicon Valley communities, including benefits and risks. PEA has extensive experience in CCE program development in California through its support in launching all three operating CCE programs (Marin, Sonoma, and the recent program in Lancaster). The final report, shared in Attachment 1, reflects the results of PEA’s comprehensive analysis, which addresses prospective CCE operations under a range of scenarios over a ten- year planning horizon, including the identification of anticipated rate/cost impacts, environmental benefits, resource composition and economic development amongst other considerations. A summary of this report is provided below. SVCCE’s Prospective Customers: Currently, Pacific Gas & Electric (“PG&E”) serves approximately 240,000 bundled customer accounts within communities of the SVCCE Study, representing a mix of residential (≈90%) and commercial (≈10%) accounts. These customers consume nearly four (4) billion kilowatt hours (“kWh”) of electric energy each year. While the majority of customers fall under the residential classification, such accounts historically consume only 34% of the total electricity delivered by PG&E while commercial accounts consume the remaining 66%. SVCCE Supply Scenarios: For purposes of the Study, PEA and the Partnership team identified three indicative supply scenarios, which were designed to test the viability of prospective CCE operations under a variety of energy resource compositions, emphasizing the SVCCE Partnership’s interest in significantly reducing greenhouse gas emissions (“GHGs”) through increased use of carbon-free electric energy sources. o Scenario 1: Match PG&E’s projected GHGs profile while exceeding PG&E’s projected renewable energy content. o Scenario 2: Exceed renewable energy procurement mandates by providing SVCCE customers with a minimum 51% renewable energy content in year one of program operations, scaling up to 66% in year 10, while also promoting a 20% reduction in electric energy sector GHG emissions relative to PG&E’s projected emissions profile by procuring additional GHG-free energy products. o Scenario 3: Maximize renewable energy and GHG-free power supplies while maintaining general parity with PG&E’s projected electric rates throughout the Study period. Projected SVCCE Impacts: Based on current market prices and various operating assumptions, the Study indicates that SVCCE demonstrates the potential for customer cost savings, significant GHG reductions and economic benefits, as outlined below: o Cost Savings: Scenarios 1 and 2 demonstrate the potential for customer cost savings ranging from 1% to 5%, relative to projected PG&E rates, over the ten-year study period. Scenario 3, which was designed to maximize clean energy deliveries to SVCCE customers, maintains general rate parity with PG&E. o Environmental Benefits: Scenario 1, which was specifically designed to match the incumbent utility’s projected GHG emissions profile, did not yield any expected emissions savings. Supply Scenario 2, which was framed to achieve specified proportionate GHG emission reductions of at least 20% relative to the incumbent utility, resulted in annual emissions reductions ranging from approximately 38,000 (Year 1 impact) to 82,000 (Year 10 impact) metric tons. Scenario 3 yielded the most significant emissions benefits – annual projected emissions reductions ranged from approximately 112,000 (Year 1 impact) to 352,000 90 (Year 10 impact) metric tons, a proportionate annual GHG reduction ranging from 60% (Year 1 impact) to 86% (Year 10 impact) relative to PG&E’s projected emission profile. o Economic Benefits: The prospective SVCCE long-term contract portfolio includes approximately 340 MW of new generating capacity, all of which is assumed to be located within California and some of which may be located within communities of the CCE Study Partners. Based on widely used industry models, such projects are expected to generate up to 11,000 construction jobs and as much as $1.4 billion in total economic output. Ongoing operation and maintenance jobs associated with such projects are expected to employ as many as 185 full time equivalent positions (FTEs) with additional annual economic output approximating $30 million. SVCCE would also employ a combination of staff and contractors, resulting in additional ongoing job creation (up to 30 FTEs per year) and related annual economic output ranging from $3 to $9 million. Risks and Sensitivity Analysis: Sensitivity analyses were performed by PEA to examine the range of impacts that could result from changes in the assumed base case. The key variables examined are: 1) power and natural gas prices; 2) renewable energy prices; 3) low carbon energy prices; 4) PG&E rates; 5) PG&E surcharges; and 6) customer participation/opt-out rates. Additionally, a “small JPA” sensitivity case was run reflective of minimal community participation in the SVCCE joint powers agency to test the viability of a much smaller CCE program, and a “perfect storm” sensitivity was run to examine the cumulative impacts of adverse changes to the key variables. The sensitivity analysis produced a range of levelized electric rates for the CCE program and PG&E. The Technical Study also highlights risks that may be faced by the CCE program as well as related risk- mitigation measures, including, but not limited to, the following: o Financial risks to SVCCE’s member municipalities in the unlikely event of CCE failure; o Financial risks that may exist in the event that procured energy volumes fall short of or exceed actual customer energy use; o Reasonably foreseen legislative and regulatory changes, which may limit a CCE’s ability to remain competitive with the incumbent utility; o Availability of renewable and carbon-free energy supplies required to meet compliance mandates, SVCCE program goals, and customer commitments; and o General market volatility and price risk. Timeline & Next Steps The graphic below provides a high level summary of the timeline for the principal milestones involved in forming a CCE program that culminates in the provision of service to enrolled customers. Key implementation activities envisioned for SVCCEP include those related to 1) CCE entity formation; 2) regulatory requirements; 3) procurement; 4) financing; 5) organization; and 6) customer noticing. JPA Formation: December 2015 – March 2016 Unless the municipal organization that will legally register as the CCE entity already exists, it must be legally established. Municipalities electing to offer or allow others to offer CCE service within their jurisdiction must do so by ordinance (Attachment 2). The two existing multi-jurisdictional CCE programs (Marin and Sonoma counties) each employ a Joint Powers Authority structure for program governance. Such a structure offers centralized administration of the operations and typically representation from each community on the Board of Directors. The 91 JPA structure also offers a legal and fiscal firewall so that the assets and liabilities of the CCE program are completely separate from the general funds of member cities. Over the past year, the Partnership project team and attorneys facilitated the development of a governance structure for a CCE program, built upon the Marin and Sonoma CCE programs. The results of this effort are embodied in the JPA Agreement for Council to review (Attachment 3). If Council introduces the ordinance, staff will return at the next City Council Meeting to present for Council consideration a Resolution approving the Joint Powers Authority Agreement establishing and authorizing participation in the Silicon Valley Clean Energy Authority. In addition, a resolution to modify agency assignments to appoint a general Director and alternate Director to represent the City of Saratoga on the Authority board will be presented for consideration. Regulatory Compliance: January 2016 – November 2016 Before aggregating customers, the CCE program must meet certain requirements set forth by the California Public Utilities Commission (CPUC). In the case of SVCCE, an Implementation Plan must be adopted by the JPA, and that Implementation Plan must be submitted to the CPUC. The Implementation Plan must include the following:  An organizational structure of the program, its operations, and its funding;  Rate setting and other costs to participants;  Provisions for disclosure and due process in setting rates and allocating costs among participants;  The methods for entering and terminating agreements with other entities;  The rights and responsibilities of program participants, including, but not limited to, consumer protection procedures, credit issues, and shutoff procedures;  Termination of the program; and  A description of the third parties that will be supplying electricity under the program, including, but not limited to, information about financial, technical, and operational capabilities. A Statement of Intent must be included with the Implementation Plan that provides for: universal access, reliability, equitable treatment of all classes of customers, and any requirements established by law or the CPUC concerning aggregated service. The CPUC has 90 days to complete a review and certify the Implementation Plan. Following certification of the Implementation Plan, the CCE entity must submit a registration packet to the CPUC, which includes:  An executed service agreement with PG&E, which may require a security deposit; and  A bond or evidence of sufficient insurance to cover any reentry fees that may be imposed against it by the CPUC for involuntarily returning customers to PG&E service. The current CCE bond amount is $100,000. The CCE program would be required to participate in the CPUC’s resource adequacy program before commencing service to customers by providing load forecasts and advance demonstration of resource adequacy compliance. More specifically, a start-up CCE program would be required to file a formal load forecast with the CEC upon execution of a primary supply contract, which triggers a 100% commitment to program launch. Procurement: May 2016 – November 2016 Power supplies must be secured several months in advance of commencing service. Power purchase agreements, with one or more power suppliers, would be negotiated, typically following a competitive selection process. Services that are required include provision of energy, capacity, renewable energy and scheduling coordination. Financing: April 2016 – October 2016 Funding must be obtained to cover program and Agency start-up activities and working capital needs. Start-up funding is typically secured early in the implementation process, as these funds are needed to conduct due diligence, planning and program development, and other critical activities leading up to service commencement. Working capital lender commitments should be secured well in advance, but actual credit drawdown need not occur until 4- 6 months prior to program launch and customer enrollment. 92 Organizational Formation: April 2016 – February 2017 Initial staff positions would be filled several months in advance of service commencement to conduct the implementation process. On an interim basis, one or more of the JPA parties are envisioned to provide some functional services to the JPA under separate service agreements. Initially, internal staff of the CCE program may be relatively small but this would likely change in the event that the CCE decides to insource various administrative and operational responsibilities and/or develops and administers new programs for its customers. Contracts with other service providers, such as for data management services, would be negotiated and put into effect well in advance of service commencement. Community Engagement & Customer Noticing January 2017 – ongoing Particularly as the commencement of service nears, the JPA will intensify its outreach efforts. By law, every customer being enrolled into the CCE program must receive a minimum of four written notifications prior to program launch. For study purposes, the Technical Feasibility Study assumes that customers will be enrolled in three phases, each comprising a third of the total customer base, over a 25-month period. Such notices must contain program terms and conditions as well as opt-out instructions and must be sent to prospective customers at least twice within the sixty-day period immediately preceding automatic enrollment. These notices are referred to as “pre-enrollment” notices. Two additional “post-enrollment” notices must be provided within the sixty-day period following customer enrollment during the statutory opt-out period. This direct mail campaign will also be paired with more cost-effective social media, collateral development, traditional advertising, and grassroots organizing (e.g. tabling at farmers markets, festivals, etc.). The partnership’s cost-share proposal (Attachment 3: JPA Agreement, Exhibit E) anticipates these approaches, which will be assimilated into a next-phase Outreach Plan, should participation in the JPA be approved. Rate Setting & Program Development: November 2016 – ongoing As a California CCE, SVCCE would have independent rate setting authority with regard to the electric generation charges imposed on its customers. Prior to service commencement, SVCCE would need to establish initial customer generation rates for each of the customer groups represented in its first operating phase or for all prospective customers within the CCE’s prospective service territory. SVCCE may decide to create a schedule of customer generation rates that generally resembles the current rate options offered by PG&E as has been the case with existing programs. This practice would facilitate customer rate comparisons and should avoid confusion that may occur if customers were to be transitioned to dissimilar tariff options. SVCCE would need to establish a schedule for ongoing rate updates and changes for future customer phases and ongoing operations. SVCCE may also choose to offer certain customer-focused programs, such as Net Energy Metering (NEM), voluntary green pricing and/or feed-in tariff (FIT) programs, at the time of service commencement. To the extent that SVCCE intends to offer such programs, specific program design would need to be completed in advance of service commencement. Sustainability Program Impacts Implementing a CCE program is the single most impactful and efficient strategy for reducing community greenhouse gas emissions. As noted in the background section of this report, CCE provides local government with the ability to transition to renewable energy sources at a faster pace and more economically than currently offered by the utility provider. As a result, CCE is a cost effective method for decreasing emissions produced by energy consumption in the community. FISCAL IMPACT The Technical Feasibility Study concludes that ~$2.9M would be needed to support the launch of the CCE program, inclusive of initial staff hires, implementation plan development, procurement, community outreach, utility bond requirement, and the initial customer notification and enrollment process. It is intended that approximately $2M of this amount will be funded by contributions from participating jurisdictions, with the remaining $900,000 financed through a bank line of credit or municipal term loan in conjunction with the additional financing needed to address 93 the purchase of electricity in advance of customer revenues (as described later in this section). These initial costs are to be recovered from operating revenues over a period of time if the CCE program if launched. Up until now, the Partnership efforts were funded by the Cities of Cupertino, Mountain View, and Sunnyvale and County of Santa Clara, each contributing a total of $170,000 to date. These four lead agencies are envisioned to contribute an additional $350,000 to support program launch with an additional $100,000 being requested as a contingency to supplement the Initial Costs of the JPA should multiple Parties decline to join. The JPA requires funding contributions, also with a contingency, from the other eight Initial Participants in lesser amounts (Exhibit E of Attachment 3). The contingency was built into the required actions of each Initial Partner at this time based on feedback provided by the Partners at a November forum. This means the City of Saratoga’s initially proposed funding contribution of $100,000 was amended to include a $50,000 contingency, for a total required contribution of $150,000. Funding for this contribution is available in the current year’s budget. Due to prudent use over the last several years, the Council Discretionary account balance has grown to $175,924, therefore the required funding contribution to join the SVCEA is available in full should Council decide to participate in the JPA. Once formed and operational, the JPA will require operating capital and significant credit capacity for its initial power supply contract. The amount is currently projected between $10M and $15M, and will depend on the size of initial program roll out. This credit requirement may be met through a bank or municipal term loan, with a repayment/refinancing period of 3-5 years. It is important to note that a portion or all of the initial loan amount will require a credit guaranty, most often provided by a single or multiple member agencies of the JPA. This guaranty stays in place until the program is operational, revenues begin flowing into JPA, and the creditor removes the guaranty requirement. The process for identifying potential banking partners and securing working capital and the necessary credit for the first energy contract is beginning under the direction of the current Partnership for presentation and decision making by the JPA Board. Beyond the costs associated with forming and operating Silicon Valley Clean Energy, it should be noted that, based upon the scenarios provided in the Technical Study, this program has the potential to reduce operational costs for its member agencies, in addition to the community at large. While rate savings cannot be guaranteed at all times, it is the stated goal of the proposed CCE to offer competitive rates to PG&E, striving for stable and lower electrical rates over the life of the program. ENVIRONMENTAL REVIEW The Ordinance to authorize participation in a Community Choice Aggregation program is exempt from the requirements of the California Environmental Quality Act (CEQA) pursuant to the State CEQA Guidelines, as it is not a “project” and has no potential to result in a direct or reasonably foreseeable indirect physical change to the environment. (14 Cal. Code Regs. § 15378(a).) Further, the ordinance is exempt from CEQA as there is no possibility that the ordinance or its implementation would have a significant effect on the environment. (14 Cal. Code Regs.§ 15061(b)(3).) The ordinance is also categorically exempt because it is an action taken by a regulatory agency to assure the maintenance, restoration, enhancement or protection of the environment. (14 Cal. Code Regs. § 15308.) NEXT STEPS If Council chooses to introduce the 1st reading of the Ordinance to authorize the implementation of the Community Choice Energy program, staff will return at the next City Council meeting, scheduled for February 3, 2016, with the following items: 1. Second reading of the Ordinance to implement the Community Choice Energy program. 2. Resolution to approve the City’s participation in the Silicon Valley Clean Energy Authority (JPA). 3. Use of funding approval to join the JPA. 4. Resolution to modify agency assignments to appoint a JPA Board Director and alternate Board Director. 94 ATTACHMENTS 1. Draft SVCCE Technical Study Report attached, and available through the following web link: http://www.svcleanenergy.org/files/managed/Document/200/FINAL%20DRAFT%20SVCCE%20Technical%2 0Study_112515.pdf 2. Community Choice Aggregation Ordinance. 3. SVCEA Joint Powers Authority Agreement to be considered at the February 3, 2016 City Council Meeting. 95 DRAFT SILICON VALLEY COMMUNITY CHOICE ENERGY TECHNICAL STUDY 11/25/2015 Prepared by Pacific Energy Advisors, Inc. This Tec hnical Study was prepared for the Silicon Valley Community Choice Energy (SVCCE) Partnership for purposes of forming a Community Choice Energy (CCE) program, whic h would provide electric generation ser vice to residential and commercial customers located within Santa Clara County. A detailed discussion of the projected operating results related to the SVCCE program is presented herein. 96 97 Draft Silicon Valley Community Choice Energy Technical Study Draft Silicon Valley Comm unity Choice Energy Tec hnical Study P R E P A R E D B Y P A C I F I C E N E R G Y A D V I S O R S , I N C . Table of Contents EXECUTIVE SUMMARY ............................................................................................................................. 1 SECTION 1: INTRODUCTION .................................................................................................................... 9 SECTION 2: STUDY METHODOLOGY ...................................................................................................... 12 Supply Scenario Overview ........................................................................................................................................... 13 Key Assumptions.............................................................................................................................................................. 15 Multi-Phase Customer Enrollment ................................................................................................................................. 16 Indicative Renewable Energy Contract Portfolio ..................................................................................................... 16 Energy Production Options & Scenario Composition ............................................................................................... 20 Scenario 1: GHG Emissions Parity and Additional Renewable Energy Supply Relative to PG&E ............. 21 Scenario 2: 20% Annual GHG Emissions Reductions; Increased Renewable Energy Procurement ............. 24 Scenario 3: Maximize GHG Emissions Reductions while Maintaining General Rate Parity.......................... 27 Costs and Rates............................................................................................................................................................... 30 Greenhouse Gas Emissions ............................................................................................................................................ 32 Economic Development Impacts ................................................................................................................................... 33 Local Economic Development Benefits Potential .................................................................................................... 36 SECTION 3: SVCCE TECHNICAL PARAMETERS (ELECTRICITY CONSUMPTION) ..................................... 38 Historical and Projected Electricity Consumption ...................................................................................................... 38 Projected Customer Mix and Energy Consumption .................................................................................................. 40 Renewable Energy Portfolio Requirements ............................................................................................................... 41 Capacity Requirements ................................................................................................................................................. 43 SECTION 4: COST OF SERVICE ELEMENTS .............................................................................................. 45 Electricity Purchases........................................................................................................................................................ 45 Renewable Energy Purchases....................................................................................................................................... 45 Electric Generation ......................................................................................................................................................... 47 Transmission and Grid Services ................................................................................................................................... 47 Start-Up Costs ................................................................................................................................................................. 47 Financing Costs ................................................................................................................................................................ 49 Billing, Metering and Data Management .................................................................................................................. 49 Staff and Other Operating Costs ............................................................................................................................... 50 Uncollectible Accounts .................................................................................................................................................... 50 Program Reserves ........................................................................................................................................................... 50 Bonding and Security Requirements ........................................................................................................................... 50 PG&E Surcharges ........................................................................................................................................................... 50 98 Draft Silicon Valley Community Choice Energy Technical Study SECTION 5: COST AND BENEFITS ANALYSIS ......................................................................................... 52 Scenario 1 Study Results ............................................................................................................................................... 52 Ratepayer Costs .......................................................................................................................................................... 52 GHG Impacts ................................................................................................................................................................ 54 Scenario 2 Study Results ............................................................................................................................................... 56 Ratepayer Costs .......................................................................................................................................................... 56 GHG Impacts ................................................................................................................................................................ 57 Scenario 3 Study Results ............................................................................................................................................... 59 Ratepayer Costs .......................................................................................................................................................... 59 GHG Impacts ................................................................................................................................................................ 60 SECTION 6: SENSITIVITY ANALYSES ...................................................................................................... 63 Power and Natural Gas Prices .................................................................................................................................... 63 Renewable Energy Costs ............................................................................................................................................... 63 Carbon-Free Energy Costs ............................................................................................................................................ 64 PG&E Rates ..................................................................................................................................................................... 64 PG&E Surcharges ........................................................................................................................................................... 65 Opt-Out Rates ................................................................................................................................................................. 65 Community Participation (Small JPA) .......................................................................................................................... 66 Perfect Storm ................................................................................................................................................................... 66 Sensitivity Results ............................................................................................................................................................ 66 SECTION 7: RISK ANALYSIS ................................................................................................................... 70 Financial Risks to SVCCE Members ............................................................................................................................. 70 Deviations between Actual Energy Use and Contracted Purchases ..................................................................... 71 Legislative and Regulatory Risk ................................................................................................................................... 72 Availability of Requisite Renewable and Carbon-Free Energy Supplies............................................................ 74 Market Volatility and Price Risk .................................................................................................................................. 75 SECTION 8: CCE FORMATION ACTIVITIES ............................................................................................. 77 CCE Entity Formation ...................................................................................................................................................... 77 Regulatory Requirements .............................................................................................................................................. 77 Procurement ..................................................................................................................................................................... 78 Financing .......................................................................................................................................................................... 78 Organization ................................................................................................................................................................... 78 Customer Notices ............................................................................................................................................................ 78 Ratesetting and Preliminary Program Development ............................................................................................... 78 SECTION 9: EVALUATION AND RECOMMENDATIONS .......................................................................... 80 APPENDIX A: SVCCE PRO FORMA ANALYSES ...................................................................................... 83 99 Draft Silicon Valley Community Choice Energy Technical Study Executive Summary Page 1 EXECUTIVE SUMMARY This Community Choice Energy ·&&( 7HFKQLFDO 6WXG\·6WXG\ ZDV SUHSDUHG IRU WKH 6LOLFRQ 9DOOH\ &RPPXQLW\&KRLFH (QHUJ\·69&&(3DUWQHUVKLS E\3DFLILF (QHUJ\$GYLVRUV ,QF ·3($under contract with the City of Sunnyvale, for purposes of describing the potential benefits and liabilities associated with forming a CCE program in Santa Clara County. Such a program would provide electric generation service to residential and business customers located within the SVCCE Partner jurisdictions. The SVCCE Partnership is sponsored by the Cities of Cupertino, Mountain View, and Sunnyvale and the County of Santa Clara. The Partnership has expanded the scope of the study to include eight additional communities in Santa Clara County including Campbell, Gilroy, Los Altos, Los Altos Hills, Los Gatos, Monte Sereno, Morgan Hill, and Saratoga, Campbell, Los Gatos, Monte Sereno, Morgan Hill and Gilroy; these 12 communities comprise the ·&&(6WXG\3DUWQHUV This Study addresses the potential benefits and liabilities associated with forming a CCE program over a ten- year planning horizon, drawing from the EHVW DYDLODEOH PDUNHW LQWHOOLJHQFH DQG 3($•V GLUHFW H[SHULHQFH ZLWK HDFK RI &DOLIRUQLD•V RSHUDWLQJ &&E programs † PEA has unique experience with regard to California CCE program evaluation, development and operation, having provided broad functional support to each operating CCE ZKLFK LQFOXGH 0DULQ &OHDQ (QHUJ\·0&(6RQRPD &OHDQ 3RZHU ·6&3 DQG /DQFDVWHU &KRLFH (QHUJ\·/&(3($utilized this direct experience to generate a set of anticipated scenarios for SVCCE operations as well as a variety of sensitivity analyses, which were framed to demonstrate how certain changes in the base case scenarios would influence anticipated operating results for the SVCCE program. 69&&(•V 3URVSHFWLYH &XVWRPHUV &XUUHQWO\3DFLILF *DV (OHFWULF ·3*(VHUYHV DSSUR[LPDWHO\FXVWRPHU DFFRXQWV ZLWKLQ communities of the CCE Study Partners UHSUHVHQWLQJ D PL[RI UHVLGHQWLDO §DQG FRPPHUFLDO § accounts. These customers consume nearly four (4) billioQ NLORZDWW KRXUV ·N:K of electric energy each year. While the majority of customers fall under the residential classification, such accounts historically consume only 34% of the total electricity delivered by PG&E while commercial accounts consume the remaining 66%. Peak customer demand within communities of the CCE Study Partners, which represents the highest level of instantaneous energy consumption throughout the year, occurs during the month of July, totaling 660 PHJDZDWWV ·0:). Under CCE service, each of these accounts would be enrolled in the SVCCE program over a three-phase implementation schedule commencing in early 2017, as later discussed in this Study. Consistent with California law, customers may elect to take service from the CCE provider or remain with 3*(D SURFHVV NQRZQ DV ·RSWLQJ-RXW )RU SXUSRVHV RI WKH 6WXG\3($XWLOL]HG FXUUHQW SDUWLFLSDWRU\VWDWLVWLFV compiled by the operating CCE programs to derive an assumed participation rate of 85% for the SVCCE program; the remaining 15% of regional customers are assumed to opt-out of the SVCCE program and would continue receiving generation service from PG&E. Customer and energy usage projections referenced throughout this Study reflect such adjustment. SVCCE Indicative Supply Scenarios For purposes of the Study, PEA and the CCE Study Partners identified three indicative supply scenarios, which were designed to test the viability of prospective CCE operations under a variety of energy resource compositions, emphasizing the SVCCE PartnerVKLS•V LQWHUHVW LQ VLJQLILFDQWO\UHGXFLQJ JUHHQKRXVH JDV HPLVVLRQV ·*+*V WKURXJK LQFUHDVHG XVH RI FDUERQ-free electric energy sources. As described to PEA, many local agencies within the region have adopted climate action plans, which recognize CCE formation as a viable opportunity to promote the achievement of targeted GHG reductions. With these considerations in mind, the following supply scenarios were constructed for purposes of completing this CCE Study: 100 Draft Silicon Valley Community Choice Energy Technical Study Page 2 Executive Summary x Scenario 1: Match the incumbent investor-RZQHG XWLOLW\•V ·,28 3DFLILF *DV (OHFWULF &RPSDQ\ ·3*(SURMHFWHG JUHHQKRXVH JDV HPLVVLRQV ·*+*V SURILOH while exceeding 3*(•V SURMHFWHG renewable energy content.1 x Scenario 2: Exceed applicable renewable energy procurement mandates by providing SVCCE customers with a minimum 51% renewable energy content in year one of program operations, scaling up to 66% in year 10, while also promoting a 20% reduction in electric energy sector GHG emissions UHODWLYH WR 3*(•V SURMHFWHG HPLVVLRQV profile by procuring additional GHG-free energy products.2 x Scenario 3: Maximize renewable energy and GHG-free power supplies while maintaining general parity with 3*(•V SURMHFWHG HOHFWULF UDWHV throughout the Study period.3 When considering the prospective supply scenarios evaluated in this Study, it should be understood that SVCCE ZRXOG QRW EH OLPLWHG WR DQ\SDUWLFXODU VFHQDULR DVVHVVHG LQ WKLV 6WXG\WKH 6WXG\•V VXSSO\VFHQDULRV were developed in cooperation with CCE Study Partner leadership for the purpose of demonstrating potential operating outcomes of a new CCE program under a broad range of resource mixes, which generally reflect key objectives of the Study participants. Prior to the procurement of any particular energy products, SVCCE would have an opportunity to refine its desired resource mix, which may differ from the prospective scenarios reflected herein. When developing 69&&(•V LQGLFDWLYH supply scenarios, PEA was directed to include additional assumptions. In particular, all scenarios include the provision of a voluntary retail service option that would provide participating customers with 100% renewable energy (presumably for a price premium); for purposes of this Study, it was assumed that only a small percentage of SVCCE customers would select this service option §2% of the projected SVCCE customer base), which is generally consistent with customer participation in other operating CCE programs. In addition, all scenarios assume the availability of current solar development incentives as well as an SVCCE-DGPLQLVWHUHG QHW HQHUJ\PHWHULQJ ·1(0 VHUYLFH RSWLRQ ZKLFK FRXOG EH XVHG to further promote the development of local, customer-sited renewable resources. PEA was also directed to exclude the use of: 1) unbundled renewable energy certificates (due to ongoing controversy focused on environmental benefit accounting for such products); 2) specified purchases from nuclear generation, which is generally unavailable to wholesale energy buyers, including CCE programs, but represents a significant SRUWLRQ RI 3*(•V HQHUJ\UHVRXUFH PL[4; and 3) coal generation,5 which is a cost-effective but highly polluting domestic power source. 1 &RQVLVWHQW ZLWK &DOLIRUQLD•V 5HQHZDEOHV 3RUWIROLR 6WDQGDUG ·536 ODZV UHWDLO VHOOHUV RI HOHFWULF HQHUJ\LQFOXGLQJ &&(V P ust procure a minimum 33% of all electricity from eligible renewable energy sources by 2020; with the recent enrollment of 6HQDWH%LOO &DOLIR UQLD•V 536S URFXUHPHQWP DQGDWHK DVE HHQLQ FUHDVHG WR E \ 2 Industry accepted GHG accounting practices generally recognize eligible renewable energy sources as GHG -free. Under the Scenario 2 portfolio composition, incremental purchases of non-RPS-eligible GHG-free sources, specifically electricity produced by larger hydroelectric resources (with nameplate generating capacity in excess of 30 megawatts) would be procured by SVCCE to achieve the noted GHG emissions reductions. 3 Under Scenario 3, the proportion of RPS -eligible renewable energy would achieve specified procurement mandates throughout the Study period. Similar to Scenario 2, additional GHG -free energy purchases would be made, subject to the specified rate constraint, in an effort to maximize the proportion of clean energy (e.g., renewable energy plus additional GHG-free energy) delivered to SVCCE customers. 4 According to PG&(•V 3RZHU &RQWHQW /DEHO RI WRWDO HOHFWULF HQHUJ\VXSSO\ZDV VRXUFHG IURP QXFOHDU JHQHUDWLQJ IDFLOLWLHV LQ D VLPLODU SURSRUWLRQ RI 3*(•V WRWDO HOHFWULF HQHUJ\VXSSO\ZDV VRXUFHG IURP QXFOHDU JHQHUDWLQJ IDFLOLWL es: 21%, as reflected in PG&E•V 3RZHU6 RXUFH’LVFOR VXUH5 HSRUW IRUW KH FDOHQGDU\HDU 5 $FFRUGLQJ WR WKH &DOLIRUQLD (QHUJ\&RPPLVVLRQ DSSUR[LPDWHO\RI &DOLIRUQLD•V WRWDO V\VWHP SRZHU PL[LV FRPSULVHG RI electric energy produced by generators using coal as the primary fuel sou rce: http://energyalmanac.ca.gov/electricity/total_system_power.html. 101 Draft Silicon Valley Community Choice Energy Technical Study Executive Summary Page 3 Projected Cost Impacts to SVCCE Customers Based on current market prices and various operating assumptions, as detailed in Section 2: Study Methodology, the Study indicates that SVCCE would be viable under a broad range of market conditions, demonstrating the potential for customer cost savings and significant GHG reductions. In particular, Scenarios 1 and 2 demonstrate the potential for customer cost savings ranging from 1% to 5%, relative to projected PG&E rates, over the ten-year study period. Scenario 3, which was designed to maximize clean energy deliveries to SVCCE customers subject to general rate parity with PG&E, demonstrated that significant environmental benefits could be achieved through such a procurement strategy: average GHG emissions reductions approximating 73% and a renewable energy content of 76% were deemed achievable at rate parity during the 10-year Study period. As previously noted, none of the prospective supply scenarios include the use of unbundled renewable energy certificates; renewable energy products will be exclusively OLPLWHG WR ·EXQGOHG GHOLYHULHV SURGXFHG E\JHQHUDWRrs primarily located within: 1) California; 2) communities of the SVCCE Study Partners; and 3) elsewhere in the western United States. General Operating Projections When reviewing the pro forma financial results associated with each of the prospective supply scenarios, as UHIOHFWHG LQ $SSHQGL[$RI WKLV 6WXG\WKH ·7RWDO &KDQJH LQ &XVWRPHU (OHFWULF &KDUJHV during each year of the study period reflects the projected net revenues (or deficits) that would be realized by SVCCE in the event that the program decided to offer customer electric rates that were equivalent to similar rates charged by PG&E. To the extent that the Total Change in Customer Electric Charges is negative, SVCCE would have the potential to offer comparatively lower customer rates/charges, relative to similar charges imposed by PG&E; to the extent that such values are positive, SVCCE would need to impose comparatively higher customer charges in order to recover expected costs. Ultimately, the disposition of any projected net revenues will be determined by SVCCE leadership during annual budgeting and rate-setting processes. For example, in the cases of Scenario 1 and Scenario 2, each year of the study period reflects the potential for net revenues. Such net revenues could be passed through to SVCCE customers in the form of comparatively lower electric rates/charges, as contemplated in this Study, utilized as working capital for program operations in an attempt to reduce program financing requirements, or SVCCE leadership could strike a balance between reduced rates and increased funding for complementary energy programs, such as Net Energy Metering, customer rebates (to promote local distributed renewable infrastructure buildout or energy efficiency, for example) as well as other similarly focused programs. SVCCE leadership would have considerable flexibility in administering the disposition of any projected net revenues, subject to any financial covenants that may be entered into by the program. Environmental Impacts With regard to 69&&(•V anticipated clean energy supply and resultant GHG emissions impacts, each prospective supply scenario yielded progressively increasing environmental benefits, resulting from the incremental addition of renewable and other GHG-free power sources. For example, Scenario 1, which was specifically designed WR PDWFK WKH LQFXPEHQW XWLOLW\•V SURMHFWHG *+*HPLVVLRQV SURILOH ZKLOH PDUJLQDOO\ exceeding proportionate renewable energy procurement of the incumbent utility), did not yield any expected emissions savings. Supply Scenario 2, which was framed to achieve specified proportionate GHG emission reductions relative to the incumbent utility, resulted in annual emissions reductions ranging from approximately 38,000 (Year 1 impact) to 82,000 (Year 10 impact) metric tons. Scenario 3 yielded the most significant emissions benefits, as current market pricing for renewable and GHG-free power sources allowed for the VLJQLILFDQW PDMRULW\RI 69&&(•V SURMHFWHG SRZHU UHVRXUFH SRUWIROLR WR EH VRurced from these supply options while still remaining at rate parity with PG&E throughout the 10-year Study period † annual projected emissions reductions ranged from approximately 112,000 (Year 1 impact) to 352,000 (Year 10 impact) 102 Draft Silicon Valley Community Choice Energy Technical Study Page 4 Executive Summary metric tons, a proportionate annual GHG reduction ranging from 60% (Year 1 impact) to 86% (Year 10 impact) UHODWLYH WR 3*(•V SURMHFWHG HPLVVLRQ SURILOH. With regard to the anticipated GHG emissions impacts reflected under each scenario, it is important to note that such estimaWHV DUH VLJQLILFDQWO\LQIOXHQFHG E\3*(•V ongoing use of nuclear generation, which is generally recognized as GHG-free. In particular, the Diablo &DQ\RQ 3RZHU 3ODQW ·’&33 SURGXFHV DSSUR[LPDWHO\RI WKH XWLOLW\•V WRWDO DQQXDO HOHFWULF HQHUJ\ requirePHQWV ’XULQJ WKH ODWWHU SRUWLRQ RI WKH 6WXG\SHULRG ’&33 ZLOO QHHG WR UHOLFHQVH WKH IDFLOLW\•V WZR UHDFWRU XQLWV LQ DQG UHVSHFWLYHO\DQG WKHUH LV VRPH XQFHUWDLQW\UHJDUGLQJ 3*(•V DELOLW\WR successfully relicense these units under the current configuration, which utilizes once-through cooling as part of facility operations † use of once-through cooling is no longer permissible within California, and affected generators must reconfigure requisite cooling systems or face discontinued operation. To the extent that 3*(•V XVH RI QXFOHDU JHQHUDWLRQ LV curtailed or suspended at some point in the future, SVCCE•V SURMHFWHG emissions reductions would significantly increase under Scenarios 2 and 3. However, due to the timing of the relicensing issue facing DCPP, substantive increases to projected environmental benefits (resulting from SURVSHFWLYH FKDQJHV WR 3*(•V QXFOHDU SRZHU VXSSO\VKRXOG QRW EH DVVXPHG GXULQJ WKH 6WXG\SHULRG The various energy supply components underlying each scenario are broadly categorized as: x Conventional Supply (generally electric generation produced through the combustion of fossil fuels, particularly natural gas within the California energy markets); x ·%XFNHW Renewable Energy Supply (generally renewable energy produced by generating resources located within or delivering power directly to California); x ·%XFNHW Renewable Energy Supply (generally renewable generation imported into California); and x Additional GHG-Free Supply (generally power from large hydro-electric generation facilities, which DUH QRW HOLJLEOH WR SDUWLFLSDWH LQ &DOLIRUQLD•V RPS certification program). For the sake of comparison, Table 1 GLVSOD\V 3*(•V SURSRUWLRQDWH XVH RI YDULRXV SRZHU VRXUFHV GXULQJ WKH most recent reporting year (2014) as well as the aggregate resource mix within the state of California, as UHSRUWHG E\WKH &DOLIRUQLD (QHUJ\&RPPLVVLRQ ·&(& During the Study period, planned increases in &DOLIRUQLD•V 536 SURFXUHPHQW PDQGDWH DQG YDULRXV RWKHU IDFWRUV ZLOO FRQWULEXWH WR SHULRGLF changes in the noted resource mix. Such changes will affect projected GHG emissions comparisons between SVCCE and PG&E. 103 Draft Silicon Valley Community Choice Energy Technical Study Executive Summary Page 5 Table 1: 2014 PG&E and California Power Mix Energy Resource 2014 PG&E Power Mix 1 2014 California Power Mix 2 Eligible Renewable 27% 20% --Biomass & Waste 5% 3% --Geothermal 5% 4% --Small Hydroelectric 1% 1% --Solar 9% 4% --Wind 7% 8% Coal 0% 6% Large Hydroelectric 8% 6% Natural Gas 24% 45% Nuclear 21% 9% Unspecified Sources of Power 21% 14% Total3 100% 100% 1Source: PG&E 2014 Power Source Disclosure Report; 2Source: California Energy Commission; 3Numbers may not add due to rounding. Projected Economic Development Benefits 69&&(•V projected long-term power contract portfolio is also expected to have the potential to generate substantial economic benefits throughout the state as a result of new renewable resource development. A moderate component of this impact is expected to occur within the local economy as a direct result of renewable infrastructure buildout to be supported by a SVCCE-administered Feed-In Tariff program, which could be designed to promote the development of smaller-scale renewable generating projects that would VXSSO\D PRGHVW SRUWLRQ RI 69&&(•V WRWDO HQHUJ\UHTXLUHPHQWV. The prospective SVCCE long-term contract portfolio, which is reflected in the anticipated resource mix for each supply scenario, includes approximately 340 MW of new generating capacity (all of which is assumed to be located within California and some of which may be located within communities of the CCE Study Partners). Based on widely used industry models, such projects are expected to generate up to 11,000 construction jobs and as much as $1.4 billion in total HFRQRPLF RXWSXW 2QJRLQJ RSHUDWLRQ DQG PDLQWHQDQFH ·20 MREV Dssociated with such projects are expected to employ as many as 185 IXOO WLPH HTXLYDOHQW SRVLWLRQV ·)7(V ZLWK DGGLWLRQDO DQQXDO HFRQRPLF output approximating $30 million. SVCCE would also employ a combination of staff and contractors, resulting in additional ongoing job creation (up to 30 FTEs per year) and related annual economic output ranging from $3 to $9 million. Consolidated Scenario Highlights The following exhibit identifies the projected operating results under each supply scenario in Year 1 of anticipated CCE operations. Additional details regarding the composition of each supply scenario are addressed in Section 2. 104 105 106 Draft Silicon Valley Community Choice Energy Technical Study Page 8 Executive Summary necessary startup funding as well as additional financing to satisfy program working capital estimates. As previously noted, LW LV 3($•V RSLQLRQ WKDW SVCCE would be operationally viable under a relatively broad range of resource planning scenarios, demonstrating the potential for customer savings as well as reduced GHG emissions. 107 Draft Silicon Valley Community Choice Energy Technical Study Section 1: Introduction Page 9 SECTION 1: INTRODUCTION This Community Choice Energy ·&&( 7HFKQLFDO 6WXG\·6WXG\ ZDV SUHSDUHG IRU WKH 6LOLFRn Valley &RPPXQLW\&KRLFH (QHUJ\·69&&(3DUWQHUVKLS E\3DFLILF (QHUJ\$GYLVRUV ,QF ·3($under contract with the City of Sunnyvale, for purposes of describing the potential benefits and liabilities associated with forming a CCE program in Santa Clara County. Such a program would provide electric generation service to residential and business customers located within the SVCCE Partner jurisdictions, which currently receive electric service from the incumbent utility, Pacific Gas & Electric Company (·3*(. The SVCCE Partnership is sponsored by the Cities of Cupertino, Mountain View, and Sunnyvale and the County of Santa Clara. The Partnership has expanded the scope of the study to include eight additional communities in Santa Clara County; the 12 communities comprise WKH ·&&(6WXG\3DUWQHUV DQG DUH LGHQWLILHG EHORZ LQ 7DEOH Table 2: Prospective SVCCE Member Communities City of Campbell City of Monte Sereno City of Cupertino City of Morgan Hill City of Gilroy City of Mountain View City of Los Altos City of Saratoga Town of Los Altos Hills City of Sunnyvale Town of Los Gatos County of Santa Clara (unincorporated areas) In consideration of its response to the 6XQQ\YDOH•V Request for Qualifications No. F15-49 for Professional Services to the Environmental Services Department in Association with the Study of Community Choice Aggregation, which was issued on November 21, 2014, PEA was retained by the City to conduct a technical study focused on the prospective formation of a CCE program serving communities of the CCE Study Partners. This Study reflects the results of a comprehensive analysis, which addresses prospective CCE operations under a range of scenarios, including the identification of anticipated rate/cost impacts, environmental benefits, resource composition and economic development amongst other considerations. When reviewing this Study, it is important to keep in mind that the findings and recommendations reflected herein are substantially influenced by current market conditions within the electric utility industry, which are subject to sudden and significant changes. PEA is an independent consulting firm specializing in providing strategic advice and technical support to various organizations within the California electricity market, particularly aspiring and operating CCE SURJUDPV 3($•V FRQVXOWDQWV KDYH EHHQ DVVLVWLQJ ORFDO JRYHUQPHQWV ZLWK WKH HYDOXDWLRQ DQG LPSOHPHQWDWLRQ RI &&(SURJUDPV VLQFH LQFOXGLQJ HDFK RI &DOLIRUQLD•V RSHUDWLRQDO &&(SURJUDPV ZKLFK LQFOXGH 0DULQ COHDQ (QHUJ\·0&(6RQRPD &OHDQ 3RZHU ·6&3 DQG /DQFDVWHU &KRLFH (QHUJ\·/&(7KLV 6WXG\UHIOHFWV operating projections that are based on the best available information, utilizing transparent, documented assumptions to provide an objective assessment regarding the prospects of CCE operation within communities of the CCE Study Partners. Such assumptions are later discussed in Section 2. However, due to the dynamic QDWXUH RI &DOLIRUQLD•V HQHUJ\PDUNHWV SDUWLFXODUO\PDUNHW prices which are subject to frequent changes, the SVCCE Partnership should confirm that the assumptions reflected in this Study generally align with future market conditions (observed at the time of any decision by the SVCCE Partnership to move forward) to promote the achievement of early-stage SVCCE operations that generally align with the operating projections reflected in this Study. To the extent that future market price benchmarks materially differ from any of the assumptions noted in Section 2 of this Study, PEA recommends updating pertinent operating projections to ensure well-informed decision-making and prudent action. 108 Draft Silicon Valley Community Choice Energy Technical Study Page 10 Section 1: Introduction :KHQ UHYLHZLQJ WKLV 6WXG\QRWH WKDW WKH WHUP &RPPXQLW\&KRLFH $JJUHJDWLRQ ·&&$ZKLFK LV UHIHUHQFHG within applicable legislation and related regulations, is currently being used interchangeably with the term &RPPXQLW\&KRLFH (QHUJ\·&&(6, a term of art that has been adopted by the SVCCE Partnership to identify its aggregation initiative. Use of the CCE acronym is becoming increasingly common when referring to similar customer aggregation programs throughout the state. For purposes of this Study, the term &RPPXQLW\&KRLFH (QHUJ\RU ·&&(is used when referring to such aggregation programs. Under existing rules administered by the &DOLIRUQLD 3XEOLF 8WLOLWLHV &RPPLVVLRQ ·CPUC , PG&E would use its transmission and distribution system to deliver the electricity supplied by SVCCE in a non-discriminatory PDQQHU DV LW FXUUHQWO\GRHV IRU LWV RZQ ·EXQGOHG VHUYLFH FXVWRPHUV (i.e., customers who receive both electric generation and delivery services from a single provider) DQG IRU ·GLUHFW DFFHVV FXVWRPHUV ZKR UHFHLYH electricity provided by competitive retail suppliers. PG&E would continue to provide all metering and billing services, and customers would receive a single electric bill each month from PG&E † HDFK FXVWRPHU•V bill would show SVCCE charges for generation services as well as charges for PG&E delivery services. Money collected by PG&E on behalf of SVCCE would be electronically transferred each day to SVCCE•V designated bank account. Following enrollment in the CCE program, SVCCE customers would continue to be eligible for PG&E- administered programs funded through distribution rates and public goods charges, including rebate and subsidy programs focused on energy efficiency and distributed solar generation. To fulfill the electric energy requirements of its customers and related compliance obligations, SVCCE would participate in the electricity market to purchase various energy products from qualified generators, brokers, and/or marketers. In the future, SVCCE may also produce electricity generated by its own power plants, which could be independently developed or acquired by the CCE. Other programs and services may be offered by SVCCE as well, such as new programs to promote conservation and/or energy efficiency, locally- situated distributed renewable generation (e.g., photovoltaic solar systems that are installed by a customer ·EHKLQG WKH PHWHU WR UHGXFH UHOLDQFH RQ RIIVLWH HQHUJ\VRXUFHV DQGRU UHGXFH RYHUDOO HQHUJ\FRVWV , electric vehicle charging, and customer load shifting DOVR NQRZQ DV ·GHPDQG UHVSRQVH . 3($•V analysis quantifies the expected benefits and liabilities of the CCE program in terms of overall operating margins, ratepayer costs, reductions in emissions of GHGs, which primarily entail carbon dioxide (·CO2 from electric generating resources used to supply customers within communities of the CCE Study Partners, and economic development impacts arising from new job creation and local spending. The remaining sections of this report are organized by subject matter as follows: Section 2: Study Methodology † describes the approach used to conduct the Study. Section 3: SVCCE Technical Parameters † describes the electric consumption patterns and electric resource requirements of prospective SVCCE customers (i.e., electricity customers located within communities of the CCE Study Partners). Section 4: Cost of Service Elements † explains the various costs that would be involved in providing electric service through a CCE program. 6 While it is generally understood that both terms refer to the same type of load serving entity, as provided for under the &DOLIRUQLD 3XEOLF 8WLOLWLHV &RGH 3($LV QRW DZDUHR I DQ\FXUUHQW UHIHUHQFHV WR WKH WHUP ·&RPPXQLW\&KRLFH (QHUJ\RU ·&&(L n such Code or applicable regulations. In consideration of this observation, SVCCE should remain aware of this terminology when communicating with jurisdictional regulatory entities or legislators regarding its prospective aggregation program to ensure that naming conventions conform with currently applicable laws and regulations which address such programs. 109 Draft Silicon Valley Community Choice Energy Technical Study Section 1: Introduction Page 11 Section 5: Cost and Benefits Analysis † details the estimated benefits and financial liabilities associated with a variety of potential resource scenarios with regard to ratepayer costs, GHG impacts, and local economic development impacts. Section 6: Sensitivity Analyses † describes the variables that are expected to have the largest impact on customer rates and shows the range of impacts associated with key variables. Section 7: Risk Analysis † highlights key risks associated with the formation and operation of a CCE program, including recommended mitigation measures for such risks. Section 8: CCE Formation Activities † summarizes the steps involved in forming a CCE program. Section 9: Evaluation and Recommendations † summarizes Study results and provides recommendations based on 3($•V analysis. Appendix A: SVCCE Pro Forma Analyses † includes pro forma operating projections for each of the three SVCCE supply scenarios addressed in this Study. 110 Draft Silicon Valley Community Choice Energy Technical Study Page 12 Section 2: Study Methodology SECTION 2: STUDY METHODOLOGY The analytical framework for the Study is a cost-of-service model that estimates all costs and anticipated revenues that would be incurred/received in providing CCE services. The Study examines projected CCE operations over a ten-year study period, including the expected economic/financial impacts related thereto. As detailed in Section 4 (Cost of Service Elements), CCE program costs include those associated with energy procurement DV ZHOO DV DGPLQLVWUDWLYH ILQDQFLQJ DQG RWKHU FRVWV WKDW ZRXOG EH LQYROYHG LQ WKH SURJUDP•V formation and ongoing operation. Total projected costs over each twelve-month period represent the amounts that must be funded through program rates DOVR NQRZQ DV WKH ·UHYHQXH UHTXLUHPHQW. Average generation rates of the CCE program, which are calculated by dividing total program costs (dollars) by total program electricity sales (kilowatt hours, kWh; or megawatt hours, MWh), were determined for each year as well as the entirety of SVCCE•V WHQ-year study period (ten-year averages were calculated on a levelized basis, as further described below) to facilitate comparisons among potential electric supply mixes and against projected PG&E rates. The CCE program would have myriad choices with regard to the types of resources that may comprise its electric supply portfolio. Such choices typically focus on the following portfolio attributes: 1) The proportion of renewable and non-renewable, or conventional, generation sources; 2) Specification of a portfolio GHG emissions rate; 3) Selection of specific generating technologies (solar photovoltaic, wind, geothermal, etc.); 4) Identification of resource locations (local, in-state, regional or a combination thereof); 5) Preferred power supply structure (power purchase agreement or, potentially, asset development/ acquisition); 6) Determination of resource scale (for example, larger ·XWLOLW\-VFDOH projects and/or smaller distributed generating resources); and 7) Duration of supply commitments (short-, mid-, long-term).7 Each of these choices presents economic and/or environmental tradeoffs. Specification of initial supply preferences, which is a fundamental component of the resource planning process, typically occurs during the implementation and operation stages by those charged with leading and overseeing the CCE program. As the CCE continues to operate over time, resource planning will remain an ongoing obligation, enabling the CCE to adapt its planning principles to changing circumstances while promoting the CCE SURJUDP•V overarching policy objectives. For purposes of this Study, PEA developed three representative supply portfolios that were evaluated on the basis of ratepayer cost, renewable energy content, GHG emissions, and economic development impacts. The objective of evaluating alternative supply scenarios is to obtain a robust set of analytical results that can be used to inform decision-makers of the inherent trade-offs that exist among various resource choices while also illustrating a reasonable range of outcomes that could be achieved through CCE implementation and operation. It should be understood that SVCCE would not be limited to any particular supply scenario assessed in this Study; the supply scenarios reflected in this Study have been developed for the sake of example, taking into consideration key objectives of the aspiring CCE program. 7 )RU SXUSRVHV RI WKLV 6WXG\D ·VKRUW-WHUP VXSSO\FRPPLWPHQW JHQHUDOO\UHIHUV WR D FRQWUDFW WHUP RI RQH WR WKUHH \HDUV LQ GXUDWLRQ D ·PLG-WHUP VXSSO\FRPPLWPHQW JHQHUDOO\UHIHUV WR D FRQWUDFW WHUP RI WKUHH WR WHQ \HDUV LQ GXUDWLRQ DQG D ·ORQJ - WHUPV XSSO\FR PPLWPHQWJ HQHUDOO\U HIHUVW RD F RQWUDFW WHUP RIW HQR UP RUH\HDUVLQ G XUDWLRQ 111 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 13 S u pp l y S c e n a r i o O v e r v i ew The following supply scenarios are representative of different choices that could be made by SVCCE with regard to overall renewable energy content, fuel sources and generator locations (of the electric resources used to supply SVCCE•V FXVWRPHUV). Each scenario embodies unique portfolio attributes and related ratepayer impacts. Subject to compliance with prevailing law and applicable regulations, California CCEs have a broad range of options when assembling supply portfolios. The three scenarios discussed in this Study also reflect the inclusion of power supply from both existing generating sources, which may supply the majority of SVCCE•V HDUO\VWDJH HQHUJ\UHTXLUHPHQWV and new renewable generation projects developed as a result of long-term power purchase agreements entered into by the CCE program, which may play an increasingly prominent role in SVCCE•V PLG- and long-term resource planning efforts. With regard to the specific sources of power supply that were considered as part of this Study, PEA was directed to exclude the use of: 1) unbundled renewable energy certificates (due to ongoing controversy focused on environmental benefit accounting for such products); 2) specified purchases from nuclear generation, which is generally unavailable to wholesale energy buyers, including CCE programs, but represents a significant portion of 3*(•V HQHUJ\UHVRXUFH PL[DQG FRDO JHQHUDWLRQ ZKLFK LV D FRVW-effective but highly polluting domestic power source. Exclusion of the aforementioned energy products will not only avoid potential controversy regarding the use of generally objectionable and/or environmentally damaging power sources, but it will DOVR HQVXUH WKDW 69&&(•V SRUWIROLR HPLVVLRQV UHSRUWLQJ UHmains consistent with potential changes in California law.8 In consideration of this direction, such products were omitted during SVCCE•V SRUWIROLR DQDO\VLV It is also noteworthy that independent development and ownership of generating resources may also be an available supply alternative for the CCE program over the longer-term planning horizon, following years of successful operations, financial reserve accrual and establishment of general creditworthiness. Because the timing of any significant CCE-sponsored resource development and ownership likely falls outside the planning horizon addressed within this Study, PEA has not incorporated SVCCE-owned resources as a component of the indicative supply scenarios discussed herein. This assumption is largely based on observations related to &DOLIRUQLD•V RSHUDWLQJ &&E programs, which have yet to pursue direct investment in generating resources; the WLPHOLQH IRU LQYHVWPHQW LQ VXFK UHVRXUFHV LV OLNHO\FRQVLVWHQW ZLWK 3($•V UHODWHG DVVXPSWLRQV UHIOHFWHG LQ WKLV Study. With regard to the three prospective SVCCE supply scenarios addressed in this Study, such scenarios were designed to evaluate a broad range of portfolio characteristics for purposes of demonstrating the inherent tradeoffs that exist when deciding between available resource options. The prospective supply portfolios were also constructed in consideration of certain key objectives that were communicated to PEA on behalf of the CCE Study Partners. These objectives generally focused on the achievement of rate competitiveness, GHG emissions reductions and increased use of renewable energy resources relative to the incumbent utility. Table 3 identifies key planning elements of each scenario addressed in this Study. 8 Assembly Bill 1110 (Ting), which has become a two-year bill, is intended to require the disclosure of portfolio emissions LQWHQVLW\WR &DOLIRUQLD•V UHWDLO HOHFWULFLW\FXVWRPHUV 7KH SURSRVHG PHWKRGRORJ\IRU VXFK GLVFORVXUHV ZRXOG QRW DOORZ WKH inclusion of environmental benefits associated with unbundled renewable energy c ertificates. 112 Draft Silicon Valley Community Choice Energy Technical Study Page 14 Section 2: Study Methodology Table 3: Key Planning Elements of Each SVCCE Indicative Supply Scenario SVCCE Supply Scenario Primary Objectives of Supply Portfolio Total Renewable Energy Content9 as % of Total Supply (Year 1; Year 10) Anticipated GHG Emissions Savings10 (Year 1; Year 10) Anticipated SVCCE Customer Cost Impacts11 (Year 1; Year 10) Scenario 1 Achieve GHG emissions parity (with PG&E) on a projected basis while H[FHHGLQJ 3*(•V expected proportion of RPS-eligible procurement YEAR 1 = 36% YEAR 10 = 49% YEAR 1 = No Change YEAR 10 = No Change YEAR 1 = 4% average savings YEAR 10 = 3% average savings Scenario 2 Increased RPS-eligible renewable energy procurement plus 20% GHG emissions reductions (relative to incumbent utility) YEAR 1 = 51% YEAR 10 = 66% YEAR 1 = 20% reduction YEAR 10 = 20% reduction YEAR 1 = 3% average savings YEAR 10 = 1% average savings Scenario 3 Maximize GHG-free power procurement (RPS- eligible renewable energy plus additional GHG-free supply) while maintaining general rate/cost parity YEAR 1 = 76% YEAR 10 = 76% YEAR 1 = 60% reduction YEAR 10 = 86% reduction YEAR 1 = ·=HUR impact YEAR 10 = ·=HUR impact Under each of the three supply scenarios, the CCE program would cause new renewable generation projects to be developed through long-term power purchase agreements. It should be recognized that developing generation in California is a difficult and time-consuming process, and developing generation within communities of the CCE Study Partners and surrounding areas may be even more difficult than in other parts of the state VXFK DV &DOLIRUQLD•V &HQWUDO 9DOOH\. Major development challenges include siting, permitting, financing and generator interconnection with the transmission system, all of which may take far longer (and result in higher costs) than originally planned. Suitable sites must be identified and placed under control of the developer, and the required land can be quite significant, particularly for photovoltaic solar projects.12 It is also common for proposed generating projects to draw opposition from local residents and interest groups, who may identify various objections to the project (e.g., habitat destruction/displacement, visual impacts and species mortality). Once a suitable site is secured and the necessary permits are in place, the project must be financed, and that financing will primarily depend upon the perceived creditworthiness of the CCE program, which may take several years to build. As previously noted, PEA has assumed that during the ten year study horizon, generation projects would be developed and financed by third parties under long-term power purchase agreements with SVCCE without direct ownership of such projects by the CCE program. 9 $OO UHQHZDEOH HQHUJ\YROXPHV DUH DVVXPHG WR EH HOLJLEOH IRU XVH LQ &DOLIRUQLD•V 5HQHZDEOHV 3RUWIROLR 6WDQGDUG ·536 program. 10 Anticipated GHG emissions impacts were determined in consideration of the GHG emissions factor associated with 69&&(•V DVVXPHG UHVRXUFHP L[D VFR PSDUHG WR WKHD VVXPHG HPLVVLRQVI DFWRUD VVRFLDWHG ZLWK3 *(•V VXSSO\S RUWIROLRZ KLFKLV H [SHFWHG to decline throughout the ten-year study period. 11 Anticipated customer cost impacts were determined in consideration of th e projected average SVCCE customer rate to be paid under each of the three prospective supply scenarios relative to the forecasted average PG&E rate. 12 Each MW of PV capacity requires approximately five to eight acres, depending upon the location and insta llation characteristics. 113 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 15 K e y A s su m p ti ons When preparing the Study, it was necessary for PEA to incorporate a variety of assumptions, which were primarily based on current market REVHUYDWLRQV DQG 3($•V GLUHFW H[SHULHQFH ZLWK &DOLIRUQLD•V RSHUDWLQJ &&( SURJUDPV 6XFK DVVXPSWLRQV ZHUH LQVWUXPHQWDO LQ GHULYLQJ 69&&(•V SURMHFWHG RSHUDWLQJ UHVXOWV DV PDQ\ actual data points, such as final contract energy pricing and future customer participation in the SVCCE program, will not be known until immediately prior to or after service commencement. For purposes of this Study, the key assumptions identified in Table 4 were incorporated to facilitate the development of SVCCE operating projections: Table 4: Key Assumptions Underlying the SVCCE Technical Study Key Assumption Description Power Supply Costs Prices for renewable energy and resource adequacy capacity are based on prices observed for recent transactions and escalated for future periods. Prices for conventional power supply utilize forward curve s based on exchange quoted futures prices for power, natural gas and GHG emissions allowances. Fees associated with wholesale scheduling, balancing and settlement with the California Independent System Operator are based on similar costs experienced by existing CCE programs. Capacity requirements and shaped energy requirements were estimated using PRQWKO\FXVWRPHU ORDG GDWD E\UDWH FODVVLILFDWLRQ DV DGMXVWHG E\3*(•V KRXUO\FODVV load profiles. PG&E Rates PG&E proposed 2016 rates (August Annual Electric True-up) and surcharges (e.g., PCIA) were applied to customer load data aggregated by major rate schedule to form the basis for the PG&E rate forecast. For future years, the forecast ZDV GHULYHG XVLQJ 3*(•V PRVW UHFHQW UHVRXUFH SODQ adjusted for changes to renewable energy content mandated by SB 350. Forecast of PCIA is based on projected PG&E power portfolio cost and forward market prices. It is assumed that CCE would provide similar rate designs and options as PG&E. Community Participation All twelve municipalities are assumed to participate. Customer Participation Service is assumed to be offered to all customers except those taking direct access and standby service. Based on average customer retention experienced by operating CCE programs, 85% of customers offered service across all customer classes are assumed to enroll. CCE Rates & Reserve CCE rates would be set to recover all program costs including power supply, administration, and debt service as well as funding a reserve equivalent to 4% of annual program costs. CCE Operations Staffing and other operating costs were estimated by benchmarking to the three currently operating CCE programs, with adjustment for differences in the number of customers served. Costs associated with administering net energy metering, demand response and energy efficiency programs were included at $1,275,000 per year. Bonds and Other Deposits CPUC Bond: $100,000 (Included in Startup Cost) PG&E Deposit: $40,000 (Included in Startup Cost) CAISO Deposit: $500,000 (Included in Working Capital) Supplier Reserve: $2,500,000 (Included in Working Capital) Startup Costs: $2,900,000 Working Capital: $9,000,000 114 Draft Silicon Valley Community Choice Energy Technical Study Page 16 Section 2: Study Methodology Key Assumption Description Rate Comparisons Rate comparisons are based on the total delivered rate between CCE service and PG&E service, with the CCE program offering a rate structure that generally parallels that of PG&E including time-of-use rate differentials that may be applicable under certain rate schedules (e.g., certain Net Energy Metered customers, which may take service under rate schedules with time-of-use rate variants). For CCE service, the total delivered rate includes the CCE charges, PG&E delivery charges, and PG&E surcharges (e.g., PCIA). For PG&E service, the total delivered rate includes PG&E generation charges and PG&E delivery charges. Renewable Portfolio Standards Study assumes the currently applicable renewable energy requirements are maintained through 2020 and increased to 50% renewable portfolio content by 2030 as mandated by SB 350. Greenhouse gas emissions rates For PG&E, used its most recent forecast of portfolio emissions rates and adjusted the rate downwards for future years for the effects of anticipated increase in renewable energy content. Assumed continued operation of Diablo Canyon Nuclear Power Plant throughout study period. For CCE, used the CARB default emissions rate applied to power purchases other than purchases from renewable and hydro-electric sources. Voluntary 100% Renewable Energy Program Assumed 2% of enrolled customers elect this option. M u l ti -Ph a s e C us t o me r E n r o ll me n t For purposes of this Study, PEA assumed a three-phase customer implementation strategy through which that would enroll customers in the following manner: 1) one-third of prospective SVCCE customers would be enrolled during the first month of service, drawing from a broad, representative cross section of the entire SVCCE customer base; 2) another third of the original customer population (i.e., half of the remaining customer population which had yet to be enrolled) would be transitioned to CCE service during the thirteenth month of operation, reflecting similar characteristics when compared with the first phase; and 3) all remaining customers not previously enrolled would be transitioned to CCE service during the twenty fifth month of program operaWLRQV 6XFK D VWUDWHJ\ZLOO DOORZ WKH &&(SURJUDP WR ·ZDON EHIRUH LWV UXQV JDLQLQJ RSHUDWLRQDO experience while the initial customer base remains relatively small (when compared to the total prospective customer population). This approach will also create an opportunity for the CCE program to ·GHEXJ potential customer service and billing issues that may arise during initial operations and will also reduce credit/collateral concerns during initial power contracting efforts. Furthermore, a multi-year phase-in strategy will serve to minimize initial working capital requirements of the SVCCE program by reducing power contract payment obligations during early operations, allowing the CCE program to build reserves for purposes of self-funding future phase-in activities. I n d i c a ti v e R e n ew a b l e E n e r g y C on t r a c t Po r t f o li o For purposes of this Study, an indicative long-term renewable energy contract portfolio, which emphasizes resource and delivery profile diversity in consideration of reasonably available project opportunities, was assembled for the SVCCE program. For example, a contract portfolio exclusively focused on solar resources would not provide for requisite energy requirements during the night; similarly, a portfolio focused on the exclusive use of wind resources would not adequately address SVCCE customer energy requirements during times of day when wind levels are low. In consideration of the unique generating characteristics associated ZLWK YDULRXV UHQHZDEOH HQHUJ\WHFKQRORJLHV 3($DVVHPEOHG 69&&(•V Lndicative renewable energy contract portfolio for purposes of creating a composite energy delivery profile that would reasonably match the manner in which SVCCE customers use electric energy. Considerable amounts of solar capacity were incorporated in the indicative supply portfolio in consideration of robust resource availability throughout 115 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 17 &DOLIRUQLD DQG 69&&(•V QHHG IRU FRQVLGHUDEOH DPRXQWV RI HOHFWULFLW\GXULQJ SHDN WLPHV RI GD\*HRWKHUPDO and landfill gas-to-energy generating technologies were also incorporated in the supply portfolio, as such resources have been successfully secured by other CCE programs and SURYLGH D VWDEOH ·EDVHVORDG HQHUJ\ delivery profile that only marginally varies over time. Wind generating capacity was also included due to its availability and general cost effectiveness in serving CCE renewable energy requirements. This indicative long-term contract portfolio was applied when analyzing each of the three supply scenarios for purposes of determining the resource planning and financial impacts associated with long-term power supply commitments that could be reasonably pursued by SVCCE. As reflected in the following table, the indicative supply portfolio phases in a variety of contracting opportunities over time, allowing the CCE program to incrementally increase long-term renewable supply commitments without unnecessarily exposing SVCCE to renewable energy price risk at a single point in time † this is a prudent resource and risk management practice in consideration of recent, ongoing price reductions that have been observed by California•V renewable energy buyers. The incremental ramp up in contracted renewable energy volumes will also serve the purpose of mitigating credit concerns that may impact the CCE program during early operations and limit the pace at which new long-term resource commitments can be made. %DVHG RQ 3($•V H[SHULHQFH &DOLIRUQLD•V WKUHH RSHUDWLng CCEs, MCE, SCP and LCE, have been successful in pursuing small- (1 to 5 MWs in size) to mid-sized (5-40 MWs in size) renewable energy contracting opportunities during early operations † the developers/owners of such projects have been able to reconcile credit concerns in consideration of the CCE•V SURMHFWHG RSHUDWLQJ UHVXOWV DQG RU UHODWLYHO\QRPLQDO FROODWHUDO postings. PEA expects that SVCCE would have similar experiences when pursuing available renewable project options. For example, prior to commencing operations and in the 24 to 36 months thereafter, it is expected that SVCCE would be able to secure long-term contract commitments with both small- and mid-sized renewable project opportunities on the basis of SVCCE•V SURMHFWHG RSHUDWLQJ UHVXOWV &DOLIRUQLD•V RWKHU operating CCEs have generally been able to pursue similar opportunities with little to no collateral obligations, utilizing the respective CCE•V SUR IRUPD RSHUDWLQJ SURMHFWLRQV DV the basis for demonstrating creditworthiness. After establishing a successful operating track record, SVCCE should be effective in pursuing larger-scale project opportunities, which may prove to be more cost competitive. PEA expects that larger-scale projects may be available following the accrual of three or more years of successful operating history, including the accumulation of prudent financial reserves and the demonstration of significant customer retention † in general, the opt-RXW VWUXFWXUH SURYLGHG IRU E\&DOLIRUQLD•V CCE legislation is viewed as a risk by many prospective project developers and energy sellers; however, the successful operating track record of &DOLIRUQLD•V H[LVWLQJ CCEs and the ongoing compilation of data related to customer participation/retention has provided compelling evidence that CCE customer counts and overall program operations will remain stable over time † LQ JHQHUDO &DOLIRUQLD•V RSHUDWLQJ CCEs have each experienced customer retention rates in excess of 80% with each successive CCE program observing increasing retention rates for its customers. This trend seems to suggest that improved familiarity with the CCE business model, a growing track record of VXFFHVV DPRQJVW &DOLIRUQLD•V RSHUDWLQJ CCE programs, and effective marketing campaigns have contributed to higher levels of customer retention over time. The indicative portfolio of long-term renewable energy contracts also reflects a significant commitment to renewable project development within communities of the CCE Study Partners † a total of 20 MWs of anticipated feed-LQ WDULII ·),7 SURMHFWV KDV EHHQ LQFOXGHG LQ WKH 6WXG\LQ FRQVLGHUDWLRQ RI WKH CCE Study Partners•LQWHUHVW LQ SURPRWLQJ ORFDO UHQHZDEOH LQIUDVWUXFWXUH EXLOGRXW DQG HFRQRPLF GHYHORSPHQW ),7 SURMHFWV are typically smaller-scale renewable development opportunities, ranging from 50 kW to 1.5 MW in size, so PEA has assumed that numerous projects will comprise the 20 MW allocation reflected in the indicative resource mix. 116 Draft Silicon Valley Community Choice Energy Technical Study Page 18 Section 2: Study Methodology For purposes of the Study, PEA has assumed a uniform portfolio of long-term renewable energy contracts for each of the three indicative supply scenarios. In practical terms, this means that each of the prospective supply scenarios reflects the resource mix described below as well as varying amounts of additional renewable and GHG-free energy procured under shorter-term contract arrangements. Such additional energy volumes will be procured/applied WR IXOILOO HDFK VFHQDULR•V VSHFLILHG UHQHZDEOH UHVRXUFH PL[ Assumed prices for such long-term transactions as well as associated capacity factors, which reflect the amount of energy produced by each resource relative to its total, potential generating capacity, were also assembled by PEA in consideration of recent renewable energy transactions and typical operating characteristics associated with the noted renewable resource types. ,W LV DOVR QRWHZRUWK\WKDW 3($•V SULFLQJ DVVXPSWLRQV UHIOHFW VLJQLILFDQW SODQQHG UHGXFWLRQV LQ WKH IHGHUDO LQYHVWPHQW WD[FUHGLW ·,7&ZKLFK LV expected to decrease from 30% to 10% for projects with initial delivery dates occurring after December 31, 2016, as well as growing demand for new renewable energy projects resulting from &DOLIRUQLD•V RPS procurement mandate increasing to 50% by 203013 † both of these considerations may impose upward pressure on renewable energy pricing. PEA has addressed this possibility through relatively conservative price assumptions when compared to the current market for renewable energy products. It is possible, of course, that Congress could extend the ITC at its current level, which would mean prices for solar power would be lower than the assumptions used in this study. It is also possible that increased demand, while applying upward pricing pressure in the near term, may promote expanded supply capabilities, which would have the effect of mitigating such price pressures over time. The specific contracting opportunities, which have been incorporated in SVCCE•V LQGLFDWLYH ORQJ-term renewable energy supply portfolio, are identified below in Table 5. Table 5: 69&&(•V ,QGLFDWLYH /RQJ-Term Renewable Energy Contract Portfolio Resource Type Year of First Delivery Capacity (MW) Capacity Factor** Assumed Price ($/MWh)*** Solar PV, utility scale 2019 100* 30% $65 Solar PV, utility scale 2023 100* 30% $65 Wind 2020 100* 35% $70 Landfill Gas to Energy 2020 10* 90% $80 Landfill Gas to Energy 2025 10* 90% $80 Geothermal 2018 50 100% $80 Solar PV, multiple FIT (local) projects 2018 5* 22% $100 Solar PV, multiple FIT (local) projects 2020 5* 24% $90 Solar PV, multiple FIT (local) projects 2021 5* 24% $90 Solar PV, multiple FIT (local) projects 2022 5* 24% $90 Total 390 MW *Denotes assumed new generating capacity to be developed as a result of long-term contracts between SVCCE and qualified renewable project developers. 340 MW of potential new, California-based renewable generating capacity has been assumed in this Study. 13 On October 7, 2015, Governor Brown signed Senate Bill 350, the Clean Energy and Pollution Reduction Act of 2015. SB LQFUHDVHV &DOLIRUQLD•V 536 WR E\DPRQJVW RWKHU FOHDQ -energy initiatives. Many details regarding implementation of SB 350 will be developed over time with oversight by applicable regulatory agencies. 117 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 19 **Capacity factors quantify the proportionate amount of energy produced by each resource relative to its total, potential gen erating capacity. For example, if a 10 MW landfill gas-to-energy generator produced 78,840 MWh per year (relative to its total generating potential of 87,600 MWhs), its capacity factor would be 90%. By comparison, solar generators have relatively low capacity factors (ranging from 20% - 30%, generally), as such generators produce no power at night and very little power during the early morning and late afternoon hours. ***Certain pricing assumptions reflect planned reductions to currently applicable incentives, which may result in increased rene wable energy prices during the ten-year planning period. To the extent that such incentives are continued at current levels and/or supply significantly increases, actual prices could be lower than reflected herein. It is important to note that a broad range of considerations, including Califor QLD•V recently increased RPS (to 50% by 2030), may influence renewable energy pricing and product availability in future years. Regarding the referenced local solar projects, which are assumed to be developed under an SVCCE- administered FIT program, the pricing assumptions for such projects were set in consideration of three key factors: 1) Prices FXUUHQWO\DYDLODEOH XQGHU 3*(•V (OHFWULF-5HQHZDEOH 0DUNHW $GMXVWLQJ 7DULII ·5H0$7 ZKLFK UHSUHVHQWV WKH FXUUHQW FRQVWUXFW RI 3*(•V ),7 SURJUDP † local project developers would be HYDOXDWLQJ 69&&(•V ),7 LQ FRQVLGHUDWLRQ RI RWKHU DYDLODEOH DOWHUQDWLYHV, so it is assumed that SVCCE would want to offer comparatively higher prices to attract such developers; 2) TKH DVVXPSWLRQ WKDW SURMHFW GHYHORSPHQW FRVWV ZLWKLQ 69&&(•V SDUWLFLSDWLQJ MXULVGLFWLRQV JHQHUDOO\ exceed project development costs in other locations; and 3) The general interest of the CCE Study Partners in providing meaningful price incentives to promote local renewable infrastructure buildout. If such a program is administered by SVCCE, FIT energy prices will need to be sufficiently high to compel project sponsors to focus development efforts on locally situated project sites † this is the primary purpose of locally-IRFXVHG ),7 SURJUDPV 0RUH VSHFLILFDOO\3*(•V 5H0$7 FXUUHQWO\RIIHUV HOLJLEOH VPDOOHU-scale solar projects a base energy price of $61.23 per MWh.14 This price is adjusted according to a schedule of Time of ’HOLYHU\RU ·72’IDFWRUV ZKLFK JHQHUDOO\LQFUHDVH WKH DQQXDO DYHUDJH SULFH SDLG WR SDUWLFLSDWLQJ VRODU generators, depending on the quantity of energy produced and delivered during peak times of day (e.g. weekdays between the hours of 3:00 and 8:00 P.M.). In general terms, the aforementioned base energy price may translate to a TOD-adjusted average price of more than $70 per MWh, depending on actual power production. PEA also assumed that project development costs, particularly land costs within the SVCCE VHUYLFH WHUULWRU\ZRXOG EH KLJKHU WKDQ DYHUDJH GHYHORSPHQW FRVWV WKURXJKRXW 3*(•V VHUYLFH WHUULWRU\:LWK these observations in mind, as well as the general concept that FIT programs are intended to incentivize local renewable infrastructure buildout, the prices associated with FIT energy productions were set at comparatively high levels, ranging from $90-$100 per MWh. Such prices reflect a premium ranging from $25-$35 per MWh relative to larger projects within optimal development locations.15 While such prices seem sufficient to promote local FIT interest, it is noteworthy that SVCCE could independently adjust such prices in the event that actual FIT participation is below (or above) desired levels. In the event that the SVCCE FIT program generates more interest and participation than originally anticipated, SVCCE could cap the program by implementing a total capacity ceiling. The cap could always be modified, but implementing a participatory ceiling would provide an additional layer of financial certainty for the FIT program. 14 3*(•V 3URJUDP3 HULRG S ULFHI RU$V -$YDLODEOH3 HDNLQJ SURGXFWVDV Q RWHG RQ3 *(•V 5H0$7Z HEVLWHR Q2FW REHU 2015: http://www.pge.com/en/b2b/energysupply/wholesaleelectricsuppliersolicitation/ReMAT/index.page . 15 1RWH WKDW 0&(•V ),7 WDULII RIIHUV VLPLODU SULFH LQFHQWLYHV WR DWWUDFW ORFDO GHYHORSHUV $FFRUGLQJ WR 0&(•V ),7 WDULII applicable prices are scheduled to incrementally decrease over time (as successive FIT projects enter the project development queue). 118 Draft Silicon Valley Community Choice Energy Technical Study Page 20 Section 2: Study Methodology E n e r g y P r o du c ti on O p ti ons & S c e n a r i o C o m pos iti on When considering the portfolio composition associated with SVCCE•V SURVSHFWLYH VXSSO\VFHQDULRV VHYHral resource types, including clean (e.g., renewable and GHG-free) and conventional (e.g., fossil-fueled, which typically entails the use of natural gas within California) energy sources, would be available to supply the electric energy requirements of SVCCE customers. With regard to renewable energy product options, &DOLIRUQLD•V FXUUHQWO\HIIHFWLYH 536 SURJUDP DOORZV IRU WKH XVH RI WKUHH GLVWLQFW UHQHZDEOH HQHUJ\SURGXFWs, which are primarily differentiated by unique delivery attributes. In particular, certain RPS-eligible renewable HQHUJ\SURGXFWV DUH UHIHUUHG WR DV ·EXQGOHG UHQHZDEOH HQHUJ\PHDQLQJ WKDW WKH SK\VLFDO HOHFWULFLW\DQG renewable attributes LH 5HQHZDEOH (QHUJ\&HUWLILFDWHV RU ·5(&V DUH ERWK GHOLYHUHG WR WKH EX\HU, whereas other RPS-HOLJLEOH SURGXFWV DUH UHIHUUHG WR DV ·XQEXQGOHG PHDQLQJ WKDW WKH UHQHZDEOH DWWULEXWHV, or RECs, are sold separately from the electric commodity. 8QGHU WKH QRPHQFODWXUH RI &DOLIRUQLD•V 536 bundled renewable energy products are categorized as Portfolio CRQWHQW &DWHJRU\·3 &&RU ·%XFNHW RU 3RUWIROLR &RQWHQW &DWHJRU\·3&&RU ·%XFNHW ,Q JHQHUDO WHUPV 3&&SURGXFWV DUH WKH PRVW FRVWO\ least objectionable and offer the most flexibility ZKHQ FRPSO\LQJ ZLWK &DOLIRUQLD•V 536 SURFXUHPHQW mandates 8QEXQGOHG UHQHZDEOH HQHUJ\RU 3RUWIROLR &RQWHQW &DWHJRU\·3&&RU ·%XFNHW , has usage limitations under the RPS program and is also the subject of ongoing philosophical debate regarding environmental impacts. For purposes of this Study, PEA was advised to exclude unbundled renewable energy products from SVCCE•V SURVSHFWLYH VXSSO\SRUWIROLRV For purposes of this Study, it was assumed that all additional GHG-free energy (i.e., GHG-free energy obtained from sources that are not RPS-eligible due to size limitations) would be produced/delivered by hydroelectric generators. In consideration of these product options, SVCCE•V WKUHH SURVSHFWLYH VXSSO\VFHQDULRV ZHUH FRQVWUXFWHG with the resource preferences reflected in Table 6. 119 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 21 Table 6: SVCCE•V Scenario-Specific Energy Resource Preferences SVCCE Supply Scenario Primary Objectives of Supply Portfolio Total Renewable Energy Content16 as % of Total Supply (Year 1; Year 10) Total PCC1- Eligible17 Renewable Energy Content as % of Total Supply (Year 1; year 10) Total PCC3- Eligible18 Renewable Energy Content as % of Total Supply (Year 1; year 10) Total GHG-Free Energy Content19 as % of Total Supply (Year 1; Year 10) Scenario 1 Achieve GHG emissions parity (with PG&E) on a projected basis while exceeding 3*(•V H[SHFWHG proportion of RPS- eligible procurement YEAR 1 = 36% YEAR 10 = 49% YEAR 1 = 27% YEAR 10 = 44% YEAR 1 = None YEAR 10 = None YEAR 1 = 63% YEAR 10 = 75% Scenario 2 Increased RPS- eligible renewable energy procurement plus 20% GHG emissions reductions (relative to incumbent utility) YEAR 1 = 51% YEAR 10 = 66% YEAR 1 = 38% YEAR 10 = 57% YEAR 1 = None YEAR 10 = None YEAR 1 = 70% YEAR 10 = 80% Scenario 3 Maximize GHG- free power procurement (RPS- eligible renewable energy plus additional GHG- free supply) while maintaining general rate/cost parity YEAR 1 = 76% YEAR 10 = 76% YEAR 1 = 57% YEAR 10 = 64% YEAR 1 = None YEAR 10 = None YEAR 1 = 85% YEAR 10 = 97% S c e n a r i o 1 : G HG E m i s si ons P a r it y a nd A dd iti on a l R e n e w a b l e E n e r g y S upp l y R e l a ti v e t o P G &E Scenario 1 was structured for the primary purpose of matching the projected GHG emissions profile DVVRFLDWHG ZLWK 3*(•V VXSSO\SRUWIROLR ZKLOH DOVR H[FHHGLQJ 3*(•V SUoportionate level of renewable energy procurement. With regard to renewable energy procurement, resource preferences within Scenario 1 were generally selected to promote compliance with the legal UHTXLUHPHQWV RI &DOLIRUQLD•V RPS in advance of 16 All renewable energy volumes are assumed to be RPS -eligible for purposes of this Study. 17 3RUWIROLR &RQWHQW &DWHJRU\RU ·%XFNHW HOLJLEOH UHQHZDEOH HQHUJ\UHVRXUFHV DUHW \SLFDOO\ORFDWHG ZLWKLQ &DOLIRUQLD EXW may also be located outside California, delivering power to California delivery points via specified energy scheduling protocols. 18 3RUWIROLR &RQWHQW &DWHJRU\RU ·%XFNHW HOLJLEOH UHQHZDEOH HQHUJ\UHVRXUFHV DUH W\SLFDOO\UHIHUUHG WR DV ·XQEXQGOHG UHQHZDEOH HQHUJ\FHUWLILFDWHV RU ·XQEXQGOHG 5(&V %XFNHW SURGXFWV DUH SURGXFHG ZKHQ PHWHUHG UHQHZDEOH HQHUJ\LV deliveUHG WR WKH JULG DQG UHSUHVHQW WKH HQYLURQPHQWDO DQG RU ·JUHHQ DWWULEXWHV DVVRFLDWHG ZLWK VXFK UHQHZDEOH HQHUJ\ production. However, Bucket 3 products are sold separately from the physical energy commodity without any associated energy delivery obligations for the seller(s) of such products. 19 Total GHG-free content equals the proportion of total supply produced by renewable energy resources plus the proportion of total supply produced by non-GHG emitting generating resources, namely non-RPS qualifying hydroelectric generators. 120 Draft Silicon Valley Community Choice Energy Technical Study Page 22 Section 2: Study Methodology applicable deadlines.20 In particular, Scenario 1 incorporates a 36% RPS-eligible renewable energy supply from day one of CCE program operations, incrementally increasing after the 2020 calendar year in FRQVLGHUDWLRQ RI &DOLIRUQLD•V WUDQVLWLRQ WR D 536 PDQGDWH )RU SXUSRVHV RI 6FHQDULR PCC3 and nuclear volumes were excluded from the renewable energy supply portfolio, replacing such volumes with additional PCC1 and PCC2 products. This substitution has the effect of increasing total renewable energy supply costs but will likely minimize philosophical objections related to the use of unbundled renewable energy products, which have become more prominent in recent years. Additional clean energy purchases, which would have the effect of reducing overall GHG emissions associated with SVCCE supply portfolio, were also incorporated, yielding a 63% GHG-free resource mix in Year 1, increasing to 75% in Year 10. A supply portfolio reflecting such a resource mix would be expected to promote highly competitive customer rates during the study period but also the lowest level of environmental benefits amongst the three prospective supply scenarios. The expected clean energy content associated with Scenario 1 is identified in Table 7, which reflects the proportionate share of purchases relative to SVCCE•V H[SHFWHG HQHUJ\ requirements. Table 7: Scenario 1 - Proportionate Share of Planned Energy Purchases Relative to SVCCE•V 3URMHFWHG Retail Sales Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10 PCC 1 Supply 27% 27% 27% 35% 35% 36% 42% 43% 44% 44% PCC 2 Supply 9% 9% 9% 2% 4% 6% 1% 2% 2% 4% PCC 3 Supply 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% Total Renewable Energy Supply 36% 36% 36% 38% 39% 41% 43% 45% 47% 49% Additional GHG- Free Energy Supply 27% 29% 31% 32% 31% 30% 29% 28% 27% 26% Total Clean Energy Supply 63% 65% 68% 69% 70% 71% 72% 73% 74% 75% Conventional Energy Supply (including CAISO* market purchases) 37% 35% 32% 31% 30% 29% 28% 27% 26% 25% ·&$,62 UHIHUV WR WKH &DOLIRUQLD ,QGHSHQGHQW 6\VWHP 2SHUDWRU WKH RUJDQL]DWLRQ UHVSRQVLEOH IRU RYHUVHHLQJ RSHUDWLRQ RI &DOLI RUQLD•V ZKROHVDOH electric transmission system and related energy markets. Energy purchases from the CAISO market are not associated with specific generating UHVRXUFHV $V VXFK &$,62 SXUFKDVHV DUH DOVR FRPPRQO\UHIHUUHG WR DV ·8QVSHFLILHG Sources of Power RU ·0DUNHW 3XUFKDVHV GXH WR WKH IDFW that these purchases are made from a pool of generating resources administered by the CAISO. Note that it is very common for CCEs to incorporate considerable quantities of Market Purchases in their respective supply portfolios (20% to 40%, for example). As previously indicated 3*(•V SRZHU VXSSO\SRUWIROLR LQFOXGHG Market Purchases in 2014. Note that numbers may not add due to rounding. As previously noted, each indicative supply scenario reflects a uniform portfolio of long-term renewable energy supply contracts, which incorporates a variety of generating technologies and related energy delivery profiles. In consideration of the expected delivery start dates and energy quantities associated with each prospective contract, SVCCE•V SRUWIROLR FRPSRVLWLRQ ZLOO VRPHZKDW FKDQJH RYHU WLPH UHIOHFWLQJ LQFUHDVHG resource diversity. 20 6WDWH ODZ UHTXLUHV 3*(WR LQFUHDVH LWV UHQHZDEOH HQHUJ\FRQWHQW WR E\%DVHG RQ 3*(•V UHFHQW 3RZHU Source Disclosure Report, which addressed power purchases and sales completed by the utility during the 2014 calendar year, its current renewable energy content is approximately 27%. An equivalent renewable supply percentage should be UHIOHFWHG LQ3 *(•V 3 RZHU&R QWHQW/D EHO Z KLFK ZDVS URYLGHG WRFXVW RPHUV RIW KHX WLOLW\LQ D U HFHQWE LOOL QVHUW 121 122 123 124 125 126 127 128 129 130 Draft Silicon Valley Community Choice Energy Technical Study Page 32 Section 2: Study Methodology electric rate utilizes net present value analysis to consolidate rate-related impacts, which occur over time, in a single number. For purposes of this Study, a levelized rate represents the constant electric rate that would yield equivalent revenues (in present value terms) if charged to customers in place of the projected series of annual rates occurring throughout the ten-year study period. Levelized costs are commonly used in the electric utility industry to provide an apples-to-apples comparative basis for projects that have cash flows occurring at different points in time. Comparing levelized total electric rates for the CCE program against levelized total electric rates for PG&E service provides a simple measure of ratepayer impacts over the entire ten-year study period. Annual impacts are also provided for each scenario and provide a more detailed picture of ratepayer impacts from year to year of program operations. G r e e nhous e G a s Em i ss i ons Each supply scenario was evaluated based on the emissions of greenhouse gases associated with electricity production as compared to similar projections prepared by PG&E (for its own supply portfolio). Based on 3($•V UHYLHZ RI 3*(•V SURMHFted annual GHG emissions factors, which have been prepared through FDOHQGDU \HDU FRQVLGHUDWLRQ DSSHDUV WR KDYH EHHQ JLYHQ WR WKH LPSDFWV RI &DOLIRUQLD•V LQFUHDVLQJ 536 procurement mandates. 3*(•V SURMHFWHG HPLVVLRQV IDFWRU VWHDGLO\GHFOLQHV WKURXJK the 2020 calendar year as additional renewable energy purchases and other prospective clean-energy purchases increase with time. 3*(•V *+*HPLVVLRQV IDFWRU SURMHFWLRQV IRU WKH ILYH-year period beginning in 2016 through 2020 are identified in the Table 1022: Table 10: PG&E GHG Emission Factor Projections (2016 through 2020) Year Emission Factor (lbs CO2/MWh) Emission Factor (Metric Tons CO2/MWh) 2016 370 0.168 2017 349 0.158 2018 328 0.149 2019 307 0.139 2020 290 0.131 For the balance of the ten-year study period, PEA assumed incremental emission reductions for the PG&E VXSSO\SRUWIROLR LQ FRQVLGHUDWLRQ RILQFUHDVHV WR &DOLIRUQLD•V 536 SURFXUHPHQW PDQGDWH and other factors, such as the launch of other California-based CCE programs, which may have the effect of reducing PG&E•V GHG emissions factor (via reductions in short-term conventional energy purchases due to declining retail sales).23 3($•V DVVXPHG DQQXDO *+*HPLVVLRQV IDFWRUV IRU WKH 3*(VXSSO\SRUWIROLR, over the balance of the ten-year study period, are reflected in Table 11: 22 PG&E, Greenhouse Gas Emission Factors: Guidance for PG&E Customers, April 2013. 23 In practical terms, it is not likely that PG&E would materially adjust renewable energy purchases or reduce carbon -free generation (from its hydroelectric and/or nuclear generators) as a result of customer departure following SVCCE formation. These carbon-free resources would generally remain in the PG&E supply portfolio without near -term adjustments for departing load. Instead, it is more likely that PG&E would reduce the amount of conventional market purchases with comparatively high emissions intensities, which would have the effect of marginally reducing its portfolio emissions factor following customer departures as the relative proportion of clean energy sources in the PG&E supply portfolio would incrementally increase. 131 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 33 Table 11: 3($•V Projected GHG Emission Factors for the PG&E Supply Portfolio (2021 through 2025) Year Emission Factor (lbs CO2/MWh) Emission Factor (Metric Tons CO2/MWh) 2021 280 0.127 2022 272 0.123 2023 264 0.120 2024 256 0.116 2025 248 0.112 The PG&E emissions profile was selected as the benchmark for comparison to promote a conservative assessment of direct emissions impacts related to CCE operations (on a head-to-KHDG EDVLV ZLWK 3*(•V anticipated supply portfolio). The GHG impacts associated with SVCCE•V VXSSO\SRUWIROLR ZLOO OLNHO\EH evaluated (by members of the public and, potentially, through new emissions reporting requirements that may EH LQFRUSRUDWHG LQ DQQXDO 3RZHU &RQWHQW /DEHO RU ·3&/UHSRrting) relative to the PG&E benchmark, which suggests that the aforementioned comparative methodology is appropriate. )RU HDFK VXSSO\VFHQDULR WKH GLIIHUHQFH LQ *+*HPLVVLRQV SURGXFHG E\WKH VFHQDULR•V assumed resource mix and the otherwise applicable PG&E supply portfolio were quantified during each year as well as the entirety of the ten-year study period. The GHG impacts were quantified in terms of total tons of CO2 emissions. E c o no m i c D e v e l op me n t I m p a c t s A key potential benefit of a CCE program is its ability to promote economic development through investment in and contracts with locally constructed renewable generating infrastructure. Such projects have the potential to stimulate a significant level of new economic activity within California by creating new jobs and spending activities during generator construction, ongoing operation and maintenance. Economic development impacts may also be significant factors when comparing expected operating costs, including generation costs, of the CCE SURJUDP WR HOHFWULF JHQHUDWLRQ FRVWV XQGHU 3*(VHUYLFH SDUWLFXODUO\ZKHQ LQLWLDO ·KHDG-to-KHDG FRVW comparisons are comparable. When performing such comparisons, it is important to acknowledge the difficulty in accurately quantifying actual economic benefits related to local project investment, particularly induced economic impacts resulting from the effects of economic multipliers. In qualitative terms, it is reasonable to assume that new development projects would stimulate new economic activity. However, as with any capital project, quantifying the specific location in which such economic benefits may occur, including job creation, is challenging due to numerous uncertainties affecting the proportion of expenditures and employment that would occur within discretely defined geographic boundaries. Certain tools, which rely on the application of industry-specific economic multipliers, have been developed to assist in completing these projections, but decision makers should be aware of the broad range of outcomes that may actually apply when interpreting analytical results. To quantify the economic impacts associated with new renewable generation projects that were incorporated in the indicative long-term renewable energy supply portfolio that was applied in each of the three energy supply scenarios, PEA XWLOL]HG WKH 1DWLRQDO 5HQHZDEOH (QHUJ\/DERUDWRU\•V ·15(/-REV (FRQRPLF Development Impact ·-(’,PRGHOV. NREL is the principal research laboratory for the United States DHSDUWPHQW RI (QHUJ\·’2(Office of Energy Efficiency and Renewable Energy and also provides research expertise for the Office of Science, and the Office of Electricity Delivery and Energy Reliability. NREL is operated for DOE by the Alliance for Sustainable Energy, LLC.24 24 National Renewable Energy Laboratory website, http://www.nrel.gov/about/, September 2, 2015. 132 Draft Silicon Valley Community Choice Energy Technical Study Page 34 Section 2: Study Methodology NREL JEDI models are publicly available, spreadsheet-based tools that were specifically designed to ·estimate the economic impacts of constructing and operating power plants, fuel production facilities, and other projects at the local (usually state) level. JEDI results are intended to be estimates, not precise predictions. Based on user-entered project-specific data or default inputs (derived from industry norms), JEDI estimates the number of jobs and economic impacts to a local area that can reasonably be supported by a power plant, fuel production facility, or other project 25 Unique JEDI models have been developed for a variety of resource types, including wind, solar, geothermal, biogas and various other generating WHFKQRORJLHV (DFK YHUVLRQ RI WKH PRGHO PD\EH GRZQORDGHG IUHH RI FKDUJH IURP 15(/•V ZHEVLWH http://www.nrel.gov/analysis/jedi/download.html. According to NREL, the JEDI models are peer reviewed and are intended to project gross job estimates. NREL also notes that it ·performed extensive interviews with power generation project developers, state tax representatives, and others in the appropriate industries to determine appropriate default values contained within the models ,Q 3($•V RSLQLRQ 15(/•V -(’,PRGHOV DUH WKH DSSURSULDWH WRROV to forecast ·RUGHU RI PDJQLWXGH local economic development impacts associated with a CCE program serving communities of the CCE Study Partners. Based on the aforementioned indicative long-term renewable energy contract portfolio that was assumed to exist under each of the three supply scenarios, PEA downloaded, populated and ran the appropriate JEDI models to derive estimates of the anticipated jobs and economic development impacts that could be created in relation to the indicative long-term contract portfolio. PEA utilized each set of economic development projections to assemble an aggregate economic impact analysis for the complete long-term contract portfolio. However, all economic development estimates within this report are presented with the understanding that subtle changes in certain expenditures (and jobs) may result in significant changes to actual economic development impacts. Key output from the JEDI models is presented within three specific categories: jobs, earnings and economic output. Within each of these broadly defined categories, JEDI models approximate the impacts of economic multipliers by quantifyLQJ WKH ·ULSSOH HIIHFW WKDW RFFXUV DV D UHVXOW RI QHZ ORFDO HFRQRPLF DFWLYLW\. JEDI models initially estimate direct economic impacts at the project site and apply economic multipliers, derived from the U.S. Bureau of Economic Analysis, the U.S. Census Bureau and other sources, to approximate impacts within the supply chain (manufacturing job creation, as an example) as well as induced economic impacts (spending that occurs as a result of activity within the first two categories) related to the project. JEDI models also address job creation and economic impacts on a temporal basis, quantifying related impacts during two specific phases of the project lifecycle: 1) construction; and 2) ongoing operation and maintenance. Forecasted economic impacts associated with the indicative long-term contract portfolio are presented in aggregate form, inclusive of all anticipated development/contract opportunities, by summing the project- specific impacts calculated by the JEDI models. This approach facilitates a high-level understanding of the prospective economic impacts that could be created through such contracts but does not address temporal nuance related to the timing and creation of economic benefits associated with specific projects. For example, the unique economic impacts of projects that will begin operation/delivery during the period extending from 2018 through 2025 have been aggregated and presented within a single scenario-specific summary table. When reviewing economic development projections within this Study, it is important to distinguish between economic impacts related to the construction period and the ongoing operation and maintenance period. All job creation estimates are presented as full time equivalent positions (·FTEs). Projections related to the 25 National Renewable Energy Laboratory website: http://www.nrel.gov/analysis/jedi/about_jedi.html, September 2, 2015. 133 134 Draft Silicon Valley Community Choice Energy Technical Study Page 36 Section 2: Study Methodology With respect to the prospective generating facilities that have been incorporated in SVCCE•V LQGLFDWLYH ORQJ- term contract portfolio, PEA assumed that the significant majority of such facilities would be developed in optimal renewable resource areas throughout California. PEA also assumed the development of 20 MW of locally situated renewable generating projects, which would be developed during the study period under long-term contract arrangements between SVCCE and third-party project developers (under an assumed SVCCE-administered FIT program) † such projects are discussed below. With regard to anticipated development projects occurring in areas outside of jurisdictions comprising the CCE Study Partners, PEA assumed that virtually all plant equipment, including turbines and other materials, would be procured outside of the &&(6WXG\3DUWQHUV•Fommunities. This equipment typically represents the largest single line item expenditure in generator construction. Requisite labor, including general site preparation and ancillary facility construction activities (concrete footings and structures not directly involved in the generation process) would DOVR GUDZ IURP &DOLIRUQLD•V EURDGHU regional workforce. When considering the following economic development benefits potential, note that virtually all impacts † other than those associated with the Local Economic Development Benefits Potential, discussed in the similarly named subsection (below) † are assumed to accrue in areas outside of Santa Clara County. With this in mind, only a relatively small portion of the total potential economic development benefits are assumed to accrue within Santa Clara County. In total, 69&&(•V LQGLFDWLYH ORQJ-term contract portfolio is projected to result in the creation of approximately 9,000-11,000 new jobs during the aggregate construction period required to complete the assumed 340 MW of new generating projects. During the construction period, individuals working directly on the projects, including electricians, engineers, construction workers and heavy equipment operators, attorneys and permitting specialists, would be responsible for as much as $475 million in new economic output of which as much as $290 million would be collected in the form of salaries and wages. Workers involved with supply chain activities, such as turbine manufacturing and assembly, cement producers and heavy equipment rental companies would be responsible for up to $600 million in new economic activity of which approximately $250 million would be collected in the form of salaries and wages. Furthermore, spending by the DIRUHPHQWLRQHG LQGLYLGXDOV DV D UHVXOW RI VDODU\DQG ZDJH FROOHFWLRQ ZRXOG ·LQGXFH RWKHU ORFDO HFRQRPLF impacts at local businesses, including restaurants, grocery stores, gas stations and other providers of goods and services, totaling as much as $300 million of which approximately $110 million would be collected as salaries and wages. In total, the locally developed generation projects identified under 69&&(•V indicative long-term contract portfolio would result in approximately $1.26 to $1.38 billion in new economic output throughout the state and local economy during the construction process. During ongoing operation of the renewable generators, it is projected that as many as 185 new jobs would be created with a total annual economic impact ranging from $18 to $28 million. It is anticipated that these jobs would remain effective as long as the generating facilities remain operational, resulting in significant, lasting impacts to the local economies of the CCE Study Partners. L oc a l E c o no mi c D e v e l op m e n t B e n e f it s Potential The primary source of local jobs and economic development impacts would be derived through projects developed under SVCCE•V DQWLFLSDWHG ),7 program, which would promote the construction of locally situated, smaller-scale (i.e., up to 1 MW of total generating capacity, per project) renewable generating projects over a period of five to seven years (and beyond, should SVCCE choose to expand this program after initial participatory limitations are achieved). Note that the 1 MW capacity limitation has been referenced in FRQVLGHUDWLRQ RI WKH ),7 SURJUDPV FXUUHQWO\DGPLQLVWHUHG E\0&(DQG 6&3 7R WKH H[WHQW WKDW 69&&(•V governing board determines to specify different project limitations for its FIT program, this would be permissible. However, SVCCE should be aware that projects in excess of 1 MW may result in additional administrative complexities due to generator registration and scheduling requirements (with the CAISO) imposed on projects in excess of the 1 MW capacity threshold. For purposes of this Study and in 135 Draft Silicon Valley Community Choice Energy Technical Study Section 2: Study Methodology Page 37 consideration of a similar FIT program offered by MCE, PEA assumed that SVCCE would eventually (by year five of program operation) support the development of approximately 20 MW of locally situated renewable generating capacity, which will likely utilize the photovoltaic solar generating technology. PEA acknowledges that a fairly aggressive FIT buildout schedule has been incorporated in the Study. However, growing familiarity with the CCE business model and an increasing appreciation amongst project developers for the ILQDQFLDO YLDELOLW\RI RSHUDWLQJ &&(V DV ZHOO DV GHFUHDVLQJ SULFHV WR EH SDLG XQGHU 3*(•V ),7 RU ·5H0$7 program, have catalyzed recent interest in CCE-DGPLQLVWHUHG ),7 SURJUDPV ,Q IDFW LQWHUHVW LQ 0&(•V ),7 KDV jumped over the past year with more than 6 MW of locally situated renewable generating capacity (out of 0&(•V WRWDO ),7 SDUWLFLSDWRU\FDS RI 0:DFWLYHO\operating or under development (with related FIT contracts in place between the developers of such projects and MCE). Ultimately, many factors may affect 69&&(•V ),7 EXLOGRXW VFKHGXOH LQFOXGLQJ WKH DYDLODELOLW\RI SURMHFW ILQDQFLQJ WR LQWHUHVWHG SURMHFW developers, actual project interconnection timelines (for most projects, interconnection will be pursued under a PG&E- administered process, which is subject to delays), price competitiveness and other factors. To the extent that 69&&(•V ),7 EXLOGRXW VFKHGule is delayed, noted economic development benefits will be deferred until such projects can be completed. Based on applicable JEDI modeling results, the prospective SVCCE FIT program would result in the creation of more than 370 local jobs during generator construction with as many as 500 additional jobs created through supply chain and induced (during the construction period) economic activity over a period ranging from five to seven years, depending on the actual period of time required to complete construction activities. As previously noted, these construction jobs are temporary, but there is also a nominal level of ongoing support for jobs supporting requisite operation and maintenance activity, which is projected to be approximately six full-time equivalent employees during each year of facility operation (which may continue for 25-30 years). Project development would also generate nearly $23 million in earnings for those working on the FIT projects, which is expected to create a total economic stimulus approximating nearly $40 million (in consideration of economic multiplier effects created by the spending of earnings/wages). Supply chain and induced impacts would also be significant totaling approximately $26 million and $71 million, respectively. It is also anticipated that SVCCE would employ 10 to 30 internal staff, depending on decisions related to outsourcing/insourcing of requisite activities, during program implementation and ongoing operation. These estimates were derived by PEA in consLGHUDWLRQ RI GLUHFW H[SHULHQFH ZRUNLQJ ZLWK &DOLIRUQLD•V RSHUDWLQJ CCE programs. Depending on staffing levels, aggregate direct salaries for such staff are estimated to range from $1 to $3 million per year with a total of $3 to $9 million in total annual local economic activity generated by SVCCE staff. These local economic development impacts are subsumed in the aggregate economic development impact totals reflected in the previous table. It is also noteworthy that PEA attempted to contact NREL regarding certain wage-related assumptions that are included in the various JEDI models, specifically whether or not SUHYDLOLQJ ZDJHV DUH UHIOHFWHG LQ VXFK DVVXPSWLRQV ,Q VSLWH RI 3($•V HIIRUWV 15(/KDV EHHQ QRQ-responsive. To the extent that prevailing wage requirements are imposed in any project-specific power purchase agreement, it is reasonable to assume that earnings and related economic development impacts may VRPHZKDW LQFUHDVH WR WKH H[WHQW WKDW 15(/•V ZDJH DVVXPSWLRQV Dre lower than applicable prevailing wages. 136 Draft Silicon Valley Community Choice Energy Technical Study Page 38 Section 3: SVCCE Technical Parameters (Electricity Consumption) SECTION 3: SVCCE TECHNICAL PARAMETERS (ELECTRICITY CONSUMPTION) H i s t o r i c a l a n d P r o j e c t e d E l e c t r i c it y C onsu m p ti on Total electric consumption for eligible customers within communities of the CCE Study Partners was provided by PG&E for the 2013 and 2014 calendar years. The PG&E historical data was used as the basis for the VWXG\•V FXVWRPHU DQG HOHFWULF ORDG IRUHFDVW %DVHG RQ 3($•V UHYLHZ RI the PG&E data set, there were 244,205 electric customers within the potential CCE service territory. These customers consumed approximately 4,771 million kilowatt-hours of electricity during the 2014 calendar year. It is noteworthy that the aforementioned customer account and usage statistics include approximately 765 accounts, which are currently served through direct access service arrangements with third party suppliers. These customers account for approximately 17% of the aforementioned energy consumption, or approximately 799 million kWh annually, within communities of the CCE Study Partners. Such usage has been excluded from the projections reflected in this Study † under direct access service arrangements, which are no longer available to California consumers26, individual customers typically engage in shorter-term contract arrangements for the provision of electric generation service. By enrolling direct access accounts in the SVCCE program, such customers would be potentially exposed to duplicate generation charges and/or may be in violation of existing supply agreements. In consideration of these potential issues, direct access accounts have been excluded from SVCCE•V SURVSHFWLYH FXVWRPHU EDVH Table 13 summarizes customer account totals and historical annual energy use within communities of the SVCCE Study Partners. When reviewing the statistics reflected in Table 13, note that the historical annual electricity usage within communities of the CCE Study 3DUWQHUV LV PRUH WKDQ GRXEOH 0&(•V WRWDO DQQXDO HQHUJ\XVH ZKLFK DSSUR[LPDWHV PLOOLRQ 0:K SHU \HDU and DSSUR[LPDWHO\WLPHV WKH VL]H RI 6&3•V DQQXDO VDOHV YROXPH Table 13: SVCCE † Electric Energy Overview Current Service Provider Customer Accounts Customer Accounts (% of Total) Energy Use (MWh) Energy Use (% of Total) 3*(·%XQGOHG electric accounts) 243,440 99.7% 3,971,985 83% Direct Access electric accounts 765 0.3% 799,268 17% Total † SVCCE Study Partners 244,205 100.0% 4,771,253 100.0% Figure 11 shows how potential electric customers are distributed throughout communities of the CCE Study Partners: the largest customer populations within the potential CCE jurisdiction include the City of Sunnyvale, the City of Mountain View, unincorporated areas of Santa Clara County, the City of Cupertino and the City of Campbell. 26 Consideration of Senate Bill 286 (Hertzberg), which would have expanded eligibility of direct access service within California, subject to the provision of increased levels of renewa ble energy supply, was recently suspended by the California legislature and is now a two-year bill. In consideration of this suspension, the participatory cap on direct access service remains capped/fixed at current levels, precluding new customer account s from enrolling in such service options. 137 Draft Silicon Valley Community Choice Energy Technical Study Section 3: SVCCE Technical Parameters (Electricity Consumption) Page 39 Figure 11: Geographic Distribution of Customers Figure 12 shows the distribution of electric consumption by municipality. The geographic distribution of energy consumption is somewhat different when compared to the service account data in Figure 11 above, indicating disproportionately higher use in certain communities (as a result of differentiated account composition, particularly higher concentrations of larger commercial and/or industrial account types, within such jurisdictions). Figure 12: Geographic Distribution of Electric Consumption In deriving the load projections used for the Study, adjustments to the base forecast were made to remove customers identified as taking service under direct access27 as it was assumed that direct access customers would remain with their current electric service provider. Further adjustments were made to estimate customer 27 Direct access allows customers to choose to receive generation service from competitive electricity providers. Currently, direct access service is not available to new customers within California. Proposed legi slation may lead to the reopening of this service option at some point in the future. 0% 5%10% 15% 20% 25% 30% Sunnyvale Mountain View Unincorporated Santa Clara Cupertino Campbell Gilroy Morgan Hill Los Gatos Los Altos Saratoga Los Altos Hills Monte Sereno 0% 5%10% 15% 20% 25% 30% 35% 40% Sunnyvale Mountain View Unincorporated Santa Clara Gilroy Cupertino Morgan Hill Campbell Los Gatos Los Altos Saratoga Los Altos Hills Monte Sereno 138 Draft Silicon Valley Community Choice Energy Technical Study Page 40 Section 3: SVCCE Technical Parameters (Electricity Consumption) opt-out rates during the statutory customer notification period when eligible customers would be offered CCE service and provided with information enabling them to opt out of the program. PEA assumed a 15% customer opt-out rate, which is generally consistent with the reported opt-out rates observed during recent expansions of the MCE program, when evaluating HDFK RI 69&&(•V SURVSHFWLYH VXSSO\scenarios. Sensitivities using different opt-out rates are presented in Section 6. Going forward, potential customers and energy consumption were projected to increase by 0.5% annually, consistent with statewide projections and reflecting impacts from the significant emphasis being placed on energy efficiency within the state. The most recent baseline sales forecast for the PG&E planning area projects an average growth in energy consumption of 1.29% between 2013 and 2025.28 Adjusting the long- term growth rate for estimates of incremental self-generation (e.g., rooftop photovoltaic systems) and achievable energy efficiency yields an annual net energy consumption increase of approximately 0.3% for the PG&E planning area.29 A slightly higher growth rate (0.5%) was used for the SVCCE sales forecast in consideration of the above average growth expected for the SVCCE area. P r o j e c t e d C us t o me r M i x a n d E n e r g y C onsu m p ti on The projections for enrolled customers (excluding direct access customers) and annual electricity consumption for the major customer classifications are shown in Table 14. Hourly electricity consumption and peak demand were estimated using hourly load profiles published by PG&E for each customer classification. Table 14: Projected Accounts Totals and Energy Use for the SVCCE Customer Base Customer Classification Customer Accounts Customer Accounts (% of Total) Energy Use (MWh) Share of Energy Use (%) Residential 218,049 90% 1,336,200 34% Small Commercial 19,120 8% 423,180 11% Medium Commercial 2,527 1% 569,501 14% Large Commercial 1,166 <1% 780,723 20% Industrial 43 <1% 771,462 19% Ag and Pumping 944 <1% 62,238 2% Street Lighting 1,588 1% 20,619 1% TOTAL* 243,437 100.0% 3,963,923** 100% Peak Demand 660 MW (July) *Numbers may not add due to rounding. **These totals exclude accounts that currently receive generation service under direct access arrangements. Also excluded are a small number of commercial customers receiving bundled service under a standby rate option, under which customers generate their own electricity and utilize the grid primarily for backup purposes. It is assumed that 69&&(•VL QLWLDO VFKHGXOH RI DYDLODEOH UDWH RSWLRQV may not accommodate such customers as the usage profile is sporadic and relatively costly to serve. As a result, the account totals and annual energy consumption statistics reflected in the ·7RWDO OLQH LWHP DUH VOLJKWO\OHVV WKDQ WKH RYHUDOO DFFRXQW WRWDOV DQG HQHUJ\XVDJH UHSRUWHG DW WKH EHJLQQLQJ RI 6HFWLRQ The hourly load forecast indicates a peak demand of approximately 660 MW (occurring during the month of July), a minimum demand of approximately 300 MW (occurring during the month of March), and an average demand of about 450 MW. The minimum demand establishes the requirement for baseload energy (constant production level), while the difference between the peak demand and the minimum demand would be met by peaking and dispatchable, load following resources. 28 Kavalec, Chris, 2015. California Energy Demand Updated Forecast, 2015 -2025. California Energy Commission, Electricity Supply Analysis Division. Publication Number: CEC-2002014-009-CMF, Table 6. 29 Ibid., Table 26 139 140 Draft Silicon Valley Community Choice Energy Technical Study Page 42 Section 3: SVCCE Technical Parameters (Electricity Consumption) SBX1 2 also specified additional requirements for the types of renewable energy products that may be used WR GHPRQVWUDWH FRPSOLDQFH ZLWK &DOLIRUQLD•V 536 $FFRUGLQJ WR WKH FXUUHQWO\HIIHFWLYH 536 SURJUDP there are WKUHH 3RUWIROLR &RQWHQW &DWHJRULHV ·3&&V RU ·%XFNHWV that have been defined in consideration of the unique product attributes associated with typical renewable energy products. x PCC1, or Bucket 1, renewable products are produced by RPS-certified renewable energy generators located within the state or by out-of-state generators that can meet strict scheduling requirements, ensuring deliverability to California. For purposes of demonstrating RPS compliance, there are no limitations with regard to the use of PCC1 products. x PCC2, or Bucket 2, renewable products are generally ·ILUPed/shaped WUDQVDFWLRQV through which the energy produced by an RPS-certified renewable energy generator is not necessarily delivered to California, but an equivalent quantity of energy from a different, non-renewable generating resource is delivered WR &DOLIRUQLD DQG ·Eundled RU associated via an electronic transaction tracking system) with the renewable attribute produced by the aforementioned RPS-certified renewable generator. As noted, PCC2 products rely on electronic transaction tracking systems to substantiate the delivery of specified quantities of RPS-eligible renewable energy. x PCC3, or Bucket 3, renewable products refer to unbundled renewable energy certificates, which are sold separately from the associated electric energy (with no physical energy delivery obligations imposed on the seller of such products). Under RPS rules, limitations apply with regard to the use of PCC2 and PCC3 products. A more detailed description of the renewable product procurement specifications applicable under the currently effective RPS program are described in Table 15. Table 15: Renewable Energy Procurement Requirements RI &DOLIRUQLD•V 536 3URJUDP Compliance Period Calendar Year Overall Procurement Target (% of Total Retail Sales) PCC1 Procurement (% of Total RPS Procurement) PCC2 Procurement (% of Total RPS Procurement)* PCC3 Procurement (% of Total RPS Procurement) CP 1 2011 20.0% CP 1 2012 20.0% CP 1 2013 20.0% CP 2 2014 21.7% CP 2 2015 23.3% CP 2 2016 25.0% CP 3 2017 27.0% CP 3 2018 29.0% CP 3 2019 31.0% CP 3 2020 33.0% *Note that PCC2 products may be used in place of PCC3 products. Beyond the 2020 calendar year, California•V RPS procurement target was recently increased to 50% by 2030 † Governor Brown signed SB 350 (De Leon and Leno), the Clean Energy and Pollution Reduction Act of 2015, on October 7, 2015; SB 350 increases &DOLIRUQLD•V 536 SURFXUHPHQW WDUJHW WR E\DPRQJVW other clean-energy initiatives. Many details related to SB 350 implementation will be developed over time with oversight by designated regulatory agencies. However, it is reasonable to assume that interim annual renewable energy procurement targets will be imposed on CCEs and other retail electricity sellers to facilitate progress towards the 50% RPS; PEA also expects that additional detail regarding renewable energy product 141 Draft Silicon Valley Community Choice Energy Technical Study Section 3: SVCCE Technical Parameters (Electricity Consumption) Page 43 eligibility, including any restrictions and/or requirements regarding the use of such products, will also become clearer during upcoming implementation efforts. For purposes of this Study, PEA assumed straight-line progress when moving from the 33% RPS mandate in WR WKH 536 PDQGDWH LQ RU DQQXDO LQFUHDVHV LQ &DOLIRUQLD•V UHQHZDEOH HQHUJ\ procurement target during the ten-year transition period. With respect to the applicability of various renewable energy products that may be eligible under the prospective 50% RPS, PEA assumed a similar product mix to that which will be allowed under the current RPS program in calendar year 2020: minimum 75% PCC1 content; maximum 10% PCC3 content. Again, final details related to the implementation of SB 350 will not be certain until implementation of this legislation commences in coordination with assigned regulatory agencies. With regard to any voluntary (above-RPS) renewable energy procurement activities, PEA has assumed that the CCE program would have discretion in how it meets such voluntary, internally imposed targets reflected in the prospective planning scenarios. Table 16 LOOXVWUDWHV 3($•V DVVXPHG 536 procurement rules as California transitions to a 50% RPS by 2030. Table 16: Projected Renewable Energy Procurement Requirements Following SB350 Implementation Compliance Period Calendar Year Overall Procurement Target (% of Total Retail Sales) PCC1 Procurement (% of Total RPS Procurement) PCC2* Procurement (% of Total RPS Procurement)* PCC3 Procurement (% of Total RPS Procurement) TBD 2021 34.7% TBD 2022 36.4% TBD 2023 38.1% TBD 2024 39.8% TBD 2025 41.5% TBD 2026 43.2% TBD 2027 44.9% TBD 2028 46.6% TBD 2029 48.3% TBD 2030 50.0% *Note that PCC2 products may be used in place of PCC3 products. C a p a c i t y R e q u i r eme n t s The CCE program would be required to demonstrate it has sufficient physical generating capacity to meet its projected peak demand (660 MW) plus a 15% planning reserve margin, in accordance with resource adequacy regulations administered by the CPUC and the CEC. A specified portion of generating capacity must be located within certain local reliability areas and the remaining capacity requirement can be met with generating plants anywhere within the CAISO system. Presently, there are two local reliability areas (as GHILQHG LQ WKH &38&•V DQQXDO 5HVRXUFH $GHTXDF\*XLGH that would apply to the CCE SURJUDP WKH ·*UHDWHU %D\$UHD DQG WKH ·2WKHU 3*($UHDV.$GGLWLRQDOO\WKH CPUC and CAISO impose a flexible capacity requirement, which must be satisfied by all California load serving entities, including CCEs, to ensure that certain quantities of reserve capacity are capable of increasing generation levels within specified time periods (to promote system reliability when the production from certain grid-connected generators quickly changes as is EHFRPLQJ LQFUHDVLQJO\FRPPRQ DV D UHVXOW RI &DOLIRUQLD•V EXLOGRXW RI LQWHUPLWWHQW UHQHZDEOH energy resources). 142 Draft Silicon Valley Community Choice Energy Technical Study Page 44 Section 3: SVCCE Technical Parameters (Electricity Consumption) %DVHG RQ 3($•V H[SHULHQFe in managing resource adequacy portfolios and compliance activities, the following resource adequacy capacity requirements were assumed to apply to SVCCE•V CCE program to meet the requirements identified above. Such resource adequacy capacity requirements are identified in Table 17. Table 17 69&&(•V 3URMHFWHG 5HVRXUFH $GHTXDF\&DSDFLW\5HTXLUHPHQWV Capacity Type Percentage of Peak Demand CAISO System 75% Greater Bay Area 14% Other PG&E Areas 26% Total 115% Accordingly, the total resource adequacy requirement for SVCCE•V ILUVW \HDU RI full operations would be approximately 631 MW per month, with approximately 75 MW of the total procured from the Greater Bay Area region, 145 MW procured from any other local reliability area in the PG&E service area, and 410 MW procured from anywhere within the CAISO northern region (NP15). Requisite resource adequacy products are typically procured/secured through one or more of the following arrangements: 1) short- to medium-term contract arrangements with the owners or controllers of qualifying generating capacity; 2) capacity attributes conferred through long-term power purchase arrangements with specified generators † such contracts typically provide the buyer with both energy and capacity products from one or more specific generating resources identified in the purchase agreement; or 3) direct ownership of generating facilities, which may be eligible to provide requisite resource adequacy capacity. 143 Draft Silicon Valley Community Choice Energy Technical Study Section 4: Cost of Service Elements Page 45 SECTION 4: COST OF SERVICE ELEMENTS This section summarizes the different types of costs that would be incurred by the CCE program in providing electric service to its customers. For each supply scenario, a detailed pro forma was developed that delineates the applicable cost of service elements. These pro forma are shown in Appendix A. E l e c t r i c i t y Pu r c h a s e s The CCE program would be financially responsible for supplying the net electric demand of all enrolled customers, and it would be able to source that supply from a variety of markets and/or through the SURJUDP•V RZQ JHQHUDWLRQ UHVRXUFHV (QHUJ\UHTXLUHPHQWV DUH ultimately financially settled by the CAISO. The CAISO plays a critical role in balancing supply and demand on D VLJQLILFDQWSRUWLRQ RI &DOLIRUQLD•V electric grid and operates short-term markets for energy as well as real-time balancing services to cover inevitable moment-to-moment fluctuations in electricity consumption (resulting from circumstances including but not limited to weather, unexpected changes in customer energy use, unexpected variances in generator operation, infrastructure outages and other situations). The CCE program would interact with the CAISO WKURXJK DQ LQWHUPHGLDU\NQRZQ DV D ·6FKHGXOLQJ &RRUGLQDWRU SHULRGLFDOO\UHSRUWLQJ XVDJH GDWD for its customers and settling with the CAISO for any imbalances (i.e., instances in which the load forecast and/or the planned generator operation differs from expectations, requiring the CAISO to balance any variances through the operation of other system resources) or transactions in the CAISO markets. Bilateral markets exist for longer term purchases, which allow hedging (i.e., contractual protection via specified/fixed product pricing over a mutually agreed upon delivery term) against the fluctuations in CAISO market prices. Longer term purchases can span many years, with the most active trading being for contracts with terms of less than three years in duration. Contracts for new generation resources typically have contract term lengths of twenty (20) years RU PRUH DOORZLQJ WKH SURMHFW GHYHORSHU RZQHU WR XWLOL]H WKH FRQWUDFW•V expected revenue stream to support project financing. Electric purchase costs were estimated using the projected energy demand during the industry-defined peak and off-peak time periods. Assumed renewable energy contracts of the CCE program, as reflected in the previously described indicative long-term contract portfolio, were subtracted from SVCCE•V H[SHFWHG peak and off-peak energy demands UHVXOWLQJ LQ D UHVLGXDO HQHUJ\UHTXLUHPHQWV RU ·QHW VKRUW ZKLFK was assumed to be met with short and mid-term contract purchases of system energy (produced by conventional generating technologies; within California, the majority of system energy is produced by generators using natural gas as a primary fuel source). R e n ew a b l e E n e r g y P u r c h a s e s Renewable energy purchases may take two forms: 1) physical electric energy bundled with associated renewable/environmental attributes; or 2) unbundled renewable/environmental attributes, which are sold separately from the physical energy commodity. As described in Section 2, unbundled RECs were not incorporated in any of the supply scenarios addressed in this Study; only bundled renewable energy resources, which were assumed to meet the product delivery specifications associated with the PCC1 and PCC2 product designations were incorporated in the indicative SVCCE supply portfolios. Purchases of renewable energy from new resources are typically made under bundled, long-term contract arrangements of 20 years or more. Shorter term purchases are common for existing renewable resources and for unbundled renewable energy certificates. 144 Draft Silicon Valley Community Choice Energy Technical Study Page 46 Section 4: Cost of Service Elements Renewable energy currently sells for a premium relative to the cost of conventional power. However, when compared to the cost of new, natural gas-fueled generation, renewable resources tend to have lower levelized costs.30 Renewable energy purchase costs were estimated using predominantly long-term contracts for new renewable energy projects as specified in the indicative long-term contract portfolio. Short-term market purchases of bundled renewable energy were assumed to fulfill SVCCE•V UHPDLQLQJ UHQHZDEOH HQHUJ\QHHGV :LWK UHJDUG WR WKH WHUP UHQHZDEOH HQHUJ\FHUWLILFDWHV RU ·5(&V LW LV LPSRUWDQW WR XQGHUVWDQG WKDW a REC is the only mechanism by which ownership of renewable energy can be demonstrated/substantiated. One REC is created for every whole MWh of metered electricity produced by a registered renewable generating facility. Within the Western United States, a tracking system known as the Western Renewable Energy *HQHUDWLRQ ,QIRUPDWLRQ 6\VWHP ·:5(*,6 KDV been developed to facilitate the management of RECs, providing a platform through which RECs can be transferred between buyers and sellers of renewable energy SURGXFWV DQG DOVR ·UHWLUHG PHDQLQJ UHPRYHG IURP WKH PDUNHWSODFH IRU SXUSRVHV RI GHPRQVWUDWLQJ legal/regulatory compliance or achievement of certain voluntary procurement objectives. All renewable HQHUJ\SURGXFWLRQ LV VXEVWDQWLDWHG YLDWKH FUHDWLRQ RI D 5(&ZKLFK RFFXUV IROORZLQJ :5(*,6•YHULILFDWLRQ RI metered energy production by a registered renewable generating resource. Use of the WREGIS system for purposes of REC accounting serves to minimize concerns regarding double-counting during compliance demonstration and public reporting † in the event that a renewable energy buyer does not possess a REC, it cannot make claims with regard to the associated environmental benefits. Again, some RECs are bundled with the associated electric energy; other RECs are sold apart from the electric commodity † VXFK 5(&V DUH DSSURSULDWHO\UHIHUUHG WR DV ·XQEXQGOHG 5(&V 7KH WUDQVDFWLRQ GRFXPHQWDWLRQ associated with each renewable energy purchase should outline applicable product specifications, including whether or not RECs are being sold with or apart from the electric commodity. In selecting its renewable energy product mix, the CCE program should be aware that California law permits the use of a limited quantity of unbundled RECs, or PCC3 product volumes, for purposes of demonstrating RPS compliance † applicable limitations were previously described in Section 3. Such products currently represent lower-cost options when compared to PCC1 and PCC2 products due to the administrative simplicity associated with such transactions. In recent years, there has been robust philosophical debate regarding the advantages and pitfalls of unbundled REC use, particularly the environmental benefits associated with such products. Significant research and documentation has been prepared regarding this topic, and SVCCE is encouraged to review such information prior to engaging in unbundled REC transactions. Organizations including the Center for Resources Solutions (the program administrator for the Green-e Energy program), the United States Environmental Protection Agency, the United States Federal Trade Commission and The Climate Registry, amongst others, have all completed research and/or issued positions regarding the use of unbundled RECs. Furthermore, Assembly Bill 1110 (Ting), which was introduced to the California legislature on February 27, 2015 but is now a two-year bill, was intended to promote the inclusion of GHG emissions intensity reporting by retail electricity suppliers (in annual Power Content Label communications). If AB 1110 moves forward next year, it could impose a retail-level emissions calculation methodology that may eliminate all GHG emissions benefits associated with unbundled RECs. ,Q FRQVLGHUDWLRQ RI WKH &&(6WXG\3DUWQHUV•SUHOLPLQDU\ planning decision to exclude the use of unbundled RECs from all prospective supply scenarios, the potential change in GHG reporting conventions contemplated under AB 1110 would not present any issues for SVCCE. 30 See for example, Table 62, Estimated Cost of New Renewable and Fossil Generation in California, California Energy Commission, March 2015. 145 Draft Silicon Valley Community Choice Energy Technical Study Section 4: Cost of Service Elements Page 47 However, if SVCCE chooses to reconsider the use of unbundled RECs at some point in the future, it should be aware that such a practice may result in the reporting of higher than anticipated portfolio emission levels. As previously discussed and in light of the perceived risks and general controversy associated with the use of unbundled RECs, the CCE Study Partners advised PEA to exclude Bucket 3 products from each of the prospective supply scenarios. E l e c t r i c G e n e r a t i on Generation projects developed or acquired by the CCE program could also supplement energy purchases. Generation costs would include development costs, capital costs for land, plant and equipment, operations and maintenance costs, and, if applicable, fuel costs. Capital costs for publicly owned utilities such as a CCE are typically financed with long-term debt, and the annual debt service would be an element of annual CCE program costs. )RU SXUSRVHV RI WKLV 6WXG\3($•V analysis did not contemplate the utilization of CCE- owned/developed generating resources during the ten-year study period for reasons previously described. T r a ns m i s s i on a nd G r i d S e r v i c e s The CAISO charges market participants, including CCEs (via the CCE•V VHOHFWHG VFKHGXOLQJ FRRUGLQDWRU IRU D number of transmission and grid management services that it performs. These include costs of managing transmission congestion, acquiring operaWLQJ UHVHUYHV DQG RWKHU ·DQFLOODU\VHUYLFHV DQG FRQGXFWLQJ &$,62 markets and other grid operations. The CAISO charges are both directly related to SVCCE•V RSHUDWLRQV EXW there are other grid charges that are shared across all load serving entities on a pro rata basis. These costs would be assessed to the Scheduling Coordinator for the CCE program, and are assumed to be directly passed through to the CCE program with no markup. S t a r t -Up C os t s Start-up costs are estimated to be nearly $2.9 million, which would provide necessary program funding during the approximate twelve-month period immediately preceding service commencement to SVCCE customers. Start-up costs include SVCCE staffing and requisite professional services, security deposits, the CCE bond/financial security requirement, communications and customer notices, data management, and other activities that must occur before the program begins providing electricity to its customers. These costs would be recovered through SVCCE rates after service commences. A breakdown of estimated start-up costs is shown in Table 18. 146 Draft Silicon Valley Community Choice Energy Technical Study Page 48 Section 4: Cost of Service Elements Table 18: Estimated SVCCE Program Start-Up Costs Cost Item Amount Internal Staff $730,000 Tec hnical Consulting and Legal Ser vices $620,000 Marketing and Comm unications $280,000 Customer Noticing and Mailers $120,000 Security Deposits $40,000 Miscellaneous Administrative and General $95,000 CCE Bond $100,000 Debt Ser vice $720,000 Other Pre-launc h Activities $180,000 Total $2,885,000 SVCCE start-up cost estimates are based on expenses incurred during the pre-launch activities of &DOLIRUQLD•V operating CCE programs. More specifically, PEA developed a start-up cost profile in consideration of the DFWXDO H[SHULHQFHV RI &DOLIRUQLD•V RSHUDWLQJ &&(SURJUDms, then scaled SVCCE start-up cost estimates based on relative size (electric energy requirements) and customer composition when compared to the representative start-up cost profile. A detailed description of each cost item is provided below. Internal Staffing: As an independently operating JPA, it is assumed that the SVCCE program will begin to hire its own staff (on an interim or full-time basis, depending on specific job responsibilities) twelve months prior to service commencement. Technical Consulting and Legal Services: Includes services provided by experienced firms and/or individuals to support the following pre-launch activities: contract negotiations (with data management providers and energy suppliers), regulatory and compliance reporting, load forecasting, rate design and ratesetting, customer rate analysis, joint mailer content development, pro forma and budget development, and other portfolio management services. Costs also include discussions, technical analysis, and negotiations (with banking and financial institutions) related to securing financing for Program operations. This line item generally addresses related costs that will be incurred during the twelve-month period immediately preceding SVCCE launch. Marketing and Communications: Includes costs specific to marketing, communications and customer outreach, which are assumed to be outsourced services for purposes of this Study. Additional costs include the design and printing of marketing materials, advertising across various media, and sponsorship of community events. Customer Noticing and Mailers: Includes costs associated with the first two customer mailers (printing and postage), which will be sent to prospective customers prior to service commencement † these notices are also FRPPRQO\UHIHUUHG WR DV·RSW -out notices. Estimates are based on costs incurred by existing CCE programs. Security Deposits: Includes amounts required to satisfy the PG&E security deposit, which equates to the monthly average PG&E service fee to be incurred by SVCCE during its first year of operation. The security deposit is typically posted around the same time as the CCE Bond (which will be posted with the CPUC). Miscellaneous Administrative and General: Includes additional overhead during the twelve-month period immediately preceding service commencement. Some of these costs include travel, office supplies, and rent for office space. 147 Draft Silicon Valley Community Choice Energy Technical Study Section 4: Cost of Service Elements Page 49 CCE Bond: An amount equal to $100,000, which SVCCE would be required to post with the CPUC prior to launching the Program. For purposes of this Study, it is assumed that the CCE Bond is posted upon certification of the Implementation Plan. Debt Service: Includes interest and principal payments associated with initial program financing. Such payment obligations are expected to commence four months prior to service commencement. Depending on 69&((•V ILQDO FUHGLW VWUXFWXUH 69&&(FRXOG SRWHQWLDOO\QHJRWLDWH WHUPV WKDW are more closely aligned with the anticipated timing of rate revenue receipt. 69&&(•V ·EULGJH-ILQDQFLQJ , which is required to ensure that the Program has adequate working capital at the time of launch and during the months immediately thereafter, is the basis for assumed debt service payments. Other Pre-Launch Activities: Includes costs related to Implementation Plan development, product and portfolio design (i.e., the compilation and description of default and voluntary retail service options as well as requisite portfolio accounting activities to ensure that all customer commitments are satisfactorily addressed), and Request for Proposal development and administration (to secure requisite data manager services, energy products and scheduling coordinator services). Costs would be incurred by SVCCE during the twelve-month period immediately preceding service commencement. F i n a n c i n g C os t s SVCCE would need access to capital for the primary purposes of covering anticipated start-up costs and working capital requirements as well as any other project financing needs that may arise. Working capital requirements are estimated at $9 million (with related debt service reflected in Table 18 above), which would cover cash flow needs, primarily arising from the timing lag between power purchase payment deadlines and the receipt of customer revenues. The noted $9 million in working capital requirements is additive to the $2.9 million in start-XS FRVWV GL VFXVVHG DERYH LQ WKH ·6WDUW-8S &RVWV VXE-section). Typical invoicing timelines for wholesale power purchase contracts require payment (IRU WKH SULRU PRQWK•V energy deliveries) by the 20th of each month. Customer payments (revenues) are typically received within sixty to ninety days following electricity delivery. The timing difference between cash outflows and inflows represents 69&&(•V working capital requirement. The possibility exists to negotiate payment timelines with power suppliers in order to reduce 69&&(•V initial working capital requirement. For example, both SCP and LCE have negotiated an additional 30 days in the supplier payment timeline, which significantly reduces HDFK RUJDQL]DWLRQ•V working capital need. B i lli n g , Me t e r i n g a nd D a t a M a n a g eme n t PG&E provides billing and metering services for all CCE programs and charges the CCE for such services in accordance with applicable tariffs, which are regulated by the CPUC. PG&E posts the meter data to a data server that the CCE program would be able to access for its power accounting and settlements. PG&E uses systems to exchange billing, payment, and other customer data electronically with competitive retail electric providers such as CCEs. While PG&E issues customer bills and processes customer payments, the CCE program will have a large amount of data to manage and must be able to exchange data with PG&E using automated processes. PEA included costs for third party data management as well as PG&E charges for billing and metering in this cost of service category. 148 Draft Silicon Valley Community Choice Energy Technical Study Page 50 Section 4: Cost of Service Elements S t a f f a nd O t h e r O p e r a ti n g C os t s Internal staffing and/or contractors would be required to manage SVCCE•V GD\-to-day operations. These activities include program management, financial administration, resource planning, marketing and communications, regulatory compliance and advocacy, and other general administration. Such costs were estimated for SVCCE based on a review of the publicly available budgets adopted by the currently operating CCE programs: Marin Clean Energy, Sonoma Clean Power, and Lancaster Choice Energy. Additional costs were included for administration of certain demand side programs anticipated to be offered by SVCCE. These programs may include customer self-generation (net energy metering) program incentives, electric vehicle charging programs, energy efficiency and demand response programs. Included in the pro forma projections for this cost element is an assumed $1,275,000 annual budget to support the administration of such programs, which is assumed to include the funding of various customer incentives that may be offered by SVCCE. SVCCE may also qualify for additional funding for administration of energy efficiency programs through application to the CPUC. Un c o l l e c ti b l e A cc oun t s CCE rates must account for the small fraction of customers who do not pay their electric bill. PG&E attempts to collect the CCE•V FKDUJHV EXW VRPH DFFRXQWV PXVW EH ZULWWHQ RII DV XQFROOHFWLEOH $Q DOORZDQFH IRU uncollectible accounts has been included as a program cost element. P r o g r a m R e s e r v e s A reasonable revenue surplus was factored in to estimated SVCCE rates to fund a reserve account that would be used for contingencies or as a rate stabilization tool. Financing also requires generation of net revenues that accumulate as reserves, as lenders typically require maintenance of debt service coverage ratios that would necessitate setting rates to yield revenues in excess of program costs. B o nd i n g a nd S e c u r it y R e q u i r eme n t s SVCCE would be required to provide a security deposit to PG&E and post a bond or other form of financial security with the CPUC as part of its registration process. The security deposit covers approximately one month of PG&E charges for billing and metering services. The CCE bond or financial security requirement, which is posted with the CPUC, is intended to cover the potential reentry costs if customers were to be involuntarily returned to PG&E. The currently effective financial security requirement is $100,000, but PG&E and other investor owned utilities have advocated changes to the methodology that could, under certain market conditions, result in extremely ODUJH ILQDQFLDOVHFXULW\UHTXLUHPHQWV 3($•V HVWLPDWH of the CCE Bond amount reflects the currently applicable specification ($100,000). However, the CCE program should actively monitor applicable regulatory proceedings, which may result in changes to this bond amount. Risks associated with such changes are discussed in additional detail within Section 7 of this Study. P G &E S u r c h a r g e s SVCCE customers will pay the CCE•V UDWHV IRU JHQHUDWLRQ VHUYLFHV 3*(•V UDWHV IRU QRQ-generation services (transmiVVLRQ GLVWULEXWLRQ SXEOLF SXUSRVH HWF DQG WZR VXUFKDUJHV WKDW DUH FXUUHQWO\LQFOXGHG LQ 3*(•V JHQHUDWLRQ UDWHV WKH )UDQFKLVH )HH 6XUFKDUJH DQG WKH 3RZHU &KDUJH ,QGLIIHUHQFH $GMXVWPHQW ·3 &,$7KHVH surcharges are not program costs per se, but thH\GR LPSDFW KRZ D FXVWRPHU•V ELOO ZLOO FRPSDUH EHWZeen PG&E bundled service and CCE service. 149 Draft Silicon Valley Community Choice Energy Technical Study Section 4: Cost of Service Elements Page 51 The franchise fee surcharge is a minor charge that ensures PG&E collects the same amount of franchise fee revenues whether a customer takes generation service from a CCE or from PG&E. The PCIA is a substantial charge that is intended to ensure that generation costs incurred by PG&E before a customer transitions to CCE VHUYLFH DUH QRW VKLIWHG WR UHPDLQLQJ 3*(EXQGOHG VHUYLFH FXVWRPHUV IROORZ LQJ D FXVWRPHU•V GHSDUture from PG&E to CCE service). For purposes of this Study, 3($•V assumed surcharges reflect the most recent advice provided by PG&E and assumed changes to the PG&E supply portfolio over time. 150 Draft Silicon Valley Community Choice Energy Technical Study Page 52 Section 5: Cost and Benefits Analysis SECTION 5: COST AND BENEFITS ANALYSIS This section contains a quantitative description of the estimated costs and benefits for each representative supply scenario. Each scenario was evaluated using the three criteria described in Section 2. Ratepayer costs and benefits are evaluated on the basis of the total electric rates customers would pay under CCE service as compared to PG&E bundled service. Total electric rates include the rates charged by the CCE program plus 3*(•V GHOLYHU\FKDUJHV DQG RWKHU VXUFKDUJHV (QYLURQPHQWDO EHQHILWV DUH HYDOXDWHG RQ WKH EDVLV of reductions in GHG (CO2) emissions relative to the reference case. Local economic benefits are evaluated on the basis of jobs and economic activity created by the CCE SURJUDP•V LQYHVWPHQWV LQ ORFDO JHQHUDWLRQ resources. When assessing the comparative environmental impacts associated with each of SVCCE•V SURVSHFWLYH VXSSO\ VFHQDULRV LW LV LPSRUWDQW WR FRQVLGHU WKH SRWHQWLDO FKDQJHV WKDW FRXOG UHVXOW IURP 3*(•V UHGXFHG RU discontinued use of nuclear electricity produced by the Diablo Canyon Power Plant ·’&33 ’&33 FXUUHQWO\ SURGXFHV DSSUR[LPDWHO\*:K RU PRUH WKDQ RI 3*(•V WRWDO SRZHU FRQWHQW SHU \HDU EXW OLFHQVHV IRU WKH IDFLOLW\•V WZR UHDFWRU XQLWV H[SLUH LQ DQG UHVSHFWLYHO\$W WKLV SRLQW LQ WLPH WKHUH LV uncertainty regDUGLQJ 3*(•V DELOLW\WR VXFFHVVIXOO\UHOLFHQVH WKHVH XQLWV XQGHU WKH FXUUHQW FRQILJXUDWLRQ ZKLFK utilizes once-through cooling as part of facility operations. Environmental concerns regarding the use of once- through cooling may present relicensing challenges for PG&E, which could result in temporary or permanent discontinued operation of DCPP. Under this scenario, which falls towards the outer years of the study period, SVCCE•V DFWXDO *+*HPLVVLRQV LPSDFW ZRXOG GUDPDWLFDOO\LPSURYH XQGHU HDFK RI WKH SURspective supply scenarios. It is also noteworthy, that discontinued DCPP operation (without the addition of equivalent generating capacity within the region) may also impose upward pressure on market energy prices and resource adequacy products. PEA recommends that the CCE Study Partners continue to monitor the relicensing status of DCPP as expiration of the existing licenses approaches. As previously discussed (in Section 2), it is important to keep in mind the planned phase-in strategy for the prospective SVCCE customer base, which is expected to occur over a three-year period. The projected operating results reflected in the Study demonstrate the impacts of a phase-in strategy that would enroll customers in the following manner: 1) one-third of prospective SVCCE customers would be enrolled during the first month of service, drawing from a broad, representative cross section of the entire SVCCE customer base; 2) another third of the original customer population (i.e., half of the remaining customer population which had yet to be enrolled) would be transitioned to CCE service during the thirteenth month of operation, reflecting similar characteristics when compared with the first phase; and 3) all remaining customers not previously enrolled would be transitioned to CCE service during the twenty fifth month of program operations. S c e n a r i o 1 S t u dy R e su lt s R a t e p a y e r Co s t s The primary objective of Scenario 1 is to PDWFK WKH *+*HPLVVLRQV LQWHQVLW\RI 3*(•V SURMHFWHG VXSSO\ portfolio while also exceeding thH LQFXPEHQW XWLOLW\•V SURSRUWLRQDWH UHQHZDEOH HQHUJ\VXSSO\ZLWKRXW WKH XVH RI XQEXQGOHG 5(&V &RQVLVWHQW ZLWK 3($•V H[SHFWDWLRQV, projected SVCCE customer rates in Scenario 1 are lower than similar rate projections for PG&E throughout the ten-year study period, with annual comparative benefits ranging from 3% to 5%. Levelized rates over the study period are projected to be 4% lower than projected PG&E rates. For a typical household using 510 kWh per month, a 4% rate difference would result in a cost reduction of approximately $5.09 per month in Year 1 of program operations. Projected average rates for the SVCCE customer base are shown in Figure 14 and Table 19, comparing total ratepayer impacts under the PG&E bundled service and CCE service options. 151 Draft Silicon Valley Community Choice Energy Technical Study Section 5: Cost and Benefits Analysis Page 53 Figure 14: Scenario 1 Annual Ratepayer Costs Table 19: Scenario 1 - Annual Total Delivered Rate Comparison Year PG&E Total (/kWh) SVCCE Total (/kWh) Percent Difference Levelized 22.27 21.49 -4% 1 19.51 18.64 -4% 2 19.94 19.08 -4% 3 20.59 19.48 -5% 4 21.29 20.35 -4% 5 21.90 21.19 -3% 6 22.42 21.80 -3% 7 23.14 22.49 -3% 8 23.78 23.14 -3% 9 24.49 23.84 -3% 10 25.19 24.47 -3% 14.0 16.0 18.0 20.0 22.0 24.0 26.0 1 2 3 4 5 6 7 8 9 10Cents Per KWhYear AVERAGE TOTAL COST COMPARISON SVCCE Service PG&E Service 152 Draft Silicon Valley Community Choice Energy Technical Study Page 54 Section 5: Cost and Benefits Analysis GH G I m p a c t s &RQVLVWHQW ZLWK WKH SULPDU\6FHQDULR SODQQLQJ REMHFWLYH 69&&(•V anticipated GHG emissions are equivalent to projected GHG emissions of the PG&E supply portfolio. A combination of renewable and other GHG-free energy purchases is assumed to achieve this environmental outcome. The following figures and tables provide additional detail regarding the respective GHG emissions profile associated with the assumed SVCCE and PG&E supply portfolios. Figure 15: Scenario 1 † Annual GHG Emissions Comparison Table 20: Scenario 1 - Annual GHG Emissions Factor Comparison (Metric Tons CO2/MWh) Year PG&E SVCCE 1 0.158 0.158 2 0.149 0.149 3 0.139 0.139 4 0.131 0.131 5 0.127 0.127 6 0.123 0.123 7 0.120 0.120 8 0.116 0.116 9 0.112 0.112 10 0.109 0.109 - 100,000 200,000 300,000 400,000 500,000 600,000 1 2 3 4 5 6 7 8 9 10CO2 Emissions (Metric Tons)Year ATTRIBUTED PORTFOLIO EMISSIONS PG&E SVCCE 153 Draft Silicon Valley Community Choice Energy Technical Study Section 5: Cost and Benefits Analysis Page 55 Figure 16: Scenario 1 † Annual Renewable Energy Content Comparison Table 21: Scenario 1 - Annual Renewable Energy Portfolio Content Year PG&E SVCCE 1 27% 36% 2 27% 36% 3 30% 36% 4 33% 38% 5 35% 39% 6 36% 41% 7 38% 43% 8 40% 45% 9 42% 47% 10 43% 49% 0% 10% 20% 30% 40% 50% 60% 1 2 3 4 5 6 7 8 9 10Renewable Portfolio ContentYear RENEWABLE ENERGY CONTENT SVCCE RENEWABLE PORTFOLIO PG&E RENEWABLE PORTFOLIO 154 Draft Silicon Valley Community Choice Energy Technical Study Page 56 Section 5: Cost and Benefits Analysis S c e n a r i o 2 S t u dy R e su lt s R a t e p a y e r Co s t s The primary objective of Scenario 2 is to increase the use of renewable energy resources while also promoting overall annual GHG emissions reductions of 20% relative to the incumbent utility. For purposes of the Study, this objective is achieved through the inclusion of renewable energy purchases that significantly exceed applicable compliance mandates (doing so without the use of unbundled RECs) as well as additional GHG-free energy purchases, which would be produced by non-RPS-eligible hydroelectric generators located within California and/or the Pacific Northwest. Under Scenario 2, projected CCE customer rates are initially lower than similar rate projections for PG&E and maintain that general relationship throughout the study period † the relationship between SVCCE and PG&E rates demonstrates marginal customer savings ranging from 1% to 4%. Levelized rates over the study period are projected to be 2% lower than projected PG&E rates. However, in consideration of typical market volatility within the electric power sector and eminent PG&E rate volatility, these results should be reasonably interpreted as reflecting only minimal rate savings throughout the study period. For a typical household using 510 kWh per month, a 2% rate difference would result in a cost reduction of approximately $2.46 per month. Projected average rates for the SVCCE customer base are shown in Figure 17 and Table 22, comparing total ratepayer impacts under the PG&E bundled service and CCE service options. Figure 17: Scenario 2 Annual Ratepayer Costs 14.0 16.0 18.0 20.0 22.0 24.0 26.0 1 2 3 4 5 6 7 8 9 10Cents Per KWhYear AVERAGE TOTAL COST COMPARISON SVCCE Service PG&E Service 155 Draft Silicon Valley Community Choice Energy Technical Study Section 5: Cost and Benefits Analysis Page 57 Table 22: Scenario 2 - Annual Total Delivered Rate Comparison Year PG&E Total (/kWh) SVCCE Total (/kWh) Percent Difference Levelized 22.27 21.80 -2% 1 19.51 18.91 -3% 2 19.94 19.36 -3% 3 20.59 19.77 -4% 4 21.29 20.62 -3% 5 21.90 21.47 -2% 6 22.42 22.11 -1% 7 23.14 22.82 -1% 8 23.78 23.49 -1% 9 24.49 24.21 -1% 10 25.19 24.86 -1% GH G I m p a c t s As a result of the significant proportion of GHG-free resources that were incorporated in Scenario 2, the CCE program is able to demonstrate the desired GHG emissions reduction target of 20% when compared to 3*(•V SURMHFWHG HPLVVLRQV SURILOH The following figures and tables provide additional detail regarding the respective GHG emissions profile associated with the assumed SVCCE and PG&E supply portfolios. Figure 18: Scenario 2 † Annual GHG Emissions Comparison - 100,000 200,000 300,000 400,000 500,000 600,000 1 2 3 4 5 6 7 8 9 10CO2 Emissions (Metric Tons)Year ATTRIBUTED PORTFOLIO EMISSIONS PG&E SVCCE 156 Draft Silicon Valley Community Choice Energy Technical Study Page 58 Section 5: Cost and Benefits Analysis Table 23: Scenario 2 - Annual GHG Emissions Factor Comparison (Metric Tons CO2/MWh) Year PG&E SVCCE 1 0.158 0.126 2 0.149 0.119 3 0.139 0.111 4 0.131 0.105 5 0.127 0.102 6 0.123 0.099 7 0.120 0.096 8 0.116 0.093 9 0.112 0.090 10 0.109 0.087 Figure 19: Scenario 2 † Annual Renewable Energy Content Comparison 0% 10% 20% 30% 40% 50% 60% 70% 1 2 3 4 5 6 7 8 9 10Renewable Portfolio ContentYear RENEWABLE ENERGY CONTENT SVCCE RENEWABLE PORTFOLIO PG&E RENEWABLE PORTFOLIO 157 Draft Silicon Valley Community Choice Energy Technical Study Section 5: Cost and Benefits Analysis Page 59 Table 24: Scenario 2 - Annual Renewable Energy Portfolio Content Year PG&E SVCCE 1 27% 51% 2 27% 51% 3 30% 51% 4 33% 51% 5 35% 53% 6 36% 56% 7 38% 58% 8 40% 61% 9 42% 63% 10 43% 66% S c e n a r i o 3 S t u dy R e su lt s R a t e p a y e r Co s t s It is generally appropriate to characterize Scenario 3 as an ·RSWLPL]HG supply scenario under which SVCCE•V projected clean energy purchases are maximized subject to the imposition of a rate constraint, which required WKDW 69&&(•V rates remain equivalent to projected PG&E rates on a levelized basis throughout the Study period. During individual years of the Study period, projected SVCCE and PG&E rates minimally differ within a range demonstrating periods of moderate customer savings (2% savings in Year 3 of projected program operations, for example) as well as negligible cost increases (which do not exceed 0.7% in any year of the Study). Consistent with the imposed rate constraint, projected SVCCE customer rates remain generally equivalent to similar rate projections for PG&E throughout the study period and typical residential customers are expected to incur monthly charges that would be approximately $0.05 below similar PG&E charges on a levelized basis. Projected average rates for the SVCCE customer base are shown in Figure 20 and Table 25, comparing total ratepayer impacts under the PG&E bundled service and CCE service options. 158 Draft Silicon Valley Community Choice Energy Technical Study Page 60 Section 5: Cost and Benefits Analysis Figure 20: Scenario 3 Annual Ratepayer Costs Table 25: Scenario 3 - Annual Total Delivered Rate Comparison Year PG&E Total (/kWh) CCE Total (/kWh) Percent Difference Levelized 22.27 22.26 0% 1 19.51 19.38 -1% 2 19.94 19.85 0% 3 20.59 20.27 -2% 4 21.29 21.15 -1% 5 21.90 21.97 0% 6 22.42 22.58 1% 7 23.14 23.26 1% 8 23.78 23.91 1% 9 24.49 24.59 0% 10 25.19 25.21 0% GH G I m p a c t s Through the substantial use of renewable and other GHG-free energy resources, Scenario 3 suggests that the CCE program could achieve substantial *+*HPLVVLRQV UHGXFWLRQV ZKHQ FRPSDUHG WR 3*(•V SURMHFWHG emissions profile. The following figures and tables provide additional detail regarding the respective GHG emissions profile associated with the assumed SVCCE and PG&E supply portfolios. 14.0 16.0 18.0 20.0 22.0 24.0 26.0 1 2 3 4 5 6 7 8 9 10Cents Per KWhYear AVERAGE TOTAL COST COMPARISON SVCCE Service PG&E Service 159 Draft Silicon Valley Community Choice Energy Technical Study Section 5: Cost and Benefits Analysis Page 61 Figure 21: Scenario 3 † Annual GHG Emissions Comparison Table 26: Scenario 3 - Annual GHG Emissions Factor Comparison (Metric Tons CO2/MWh) Year PG&E SVCCE 1 0.158 0.064 2 0.149 0.055 3 0.139 0.045 4 0.131 0.037 5 0.127 0.033 6 0.123 0.029 7 0.120 0.025 8 0.116 0.022 9 0.112 0.018 10 0.109 0.015 - 100,000 200,000 300,000 400,000 500,000 600,000 1 2 3 4 5 6 7 8 9 10CO2 Emissions (Metric Tons)Year ATTRIBUTED PORTFOLIO EMISSIONS PG&E SVCCE 160 Draft Silicon Valley Community Choice Energy Technical Study Page 62 Section 5: Cost and Benefits Analysis Figure 22: Scenario 3 † Annual Renewable Energy Content Comparison Table 27: Scenario 3 - Annual Renewable Energy Portfolio Content Year PG&E SVCCE 1 27% 76% 2 27% 76% 3 30% 76% 4 33% 76% 5 35% 76% 6 36% 76% 7 38% 76% 8 40% 76% 9 42% 76% 10 43% 76% 0% 10% 20% 30% 40% 50% 60% 70% 80% 1 2 3 4 5 6 7 8 9 10Renewable Portfolio ContentYear RENEWABLE ENERGY CONTENT SVCCE RENEWABLE PORTFOLIO PG&E RENEWABLE PORTFOLIO 161 Draft Silicon Valley Community Choice Energy Technical Study Section 6: Sensitivity Analyses Page 63 SECTION 6: SENSITIVITY ANALYSES The economic analysis uses base case input assumptions for many variable factors that influence relative costs of the CCE program. Sensitivity analyses were performed to examine the range of impacts that could result from changes in the most significant variables (relative to base case values). The key variables examined are: 1) power and natural gas prices; 2) renewable energy prices; 3) low carbon energy prices; 4) PG&E rates; 5) PG&E surcharges; and 6) customer participation/opt-out rates. $GGLWLRQDOO\D ·VPDOO -3$VHQVLWLYLW\FDVH was run reflective of minimal community participation in the SVCCE joint powers agency to test the viability of D PXFK VPDOOHU &&(SURJUDP DQG D ·SHUIHFW VWRUP VHQVLWLYLW\ZDV UXQ WR H[DPLQH WKH FXPXODWLYH LPSDFWV RI adverse changes to the key variables. Po we r a n d N a t u r a l G a s P r i c e s Electric power prices in California are substantially influenced by natural gas prices, as natural gas-fired generation is predominantly used as the marginal resource ZLWKLQ WKH VWDWH•V system dispatch order. This fact is consistent with how PEA developed the ten-year power price forecast in which a detailed natural gas forecast was assembled and then converted to power prices using factors consistent with industry standards. Changes in natural gas prices will also tend to change the power purchase costs of the CCE program. To the extent that SVCCE•V VHOHFWHd supply portfolio excludes the use of conventional energy supply, the potential impact related to price volatility within the natural gas market will be minimized. Such changes also influence 3*(•V UDWHV EXW WKH UHODWLYH FRVW LPSDFWV ZLOO GLIIHU GHSHQGing upon the proportionate use of conventional resources utilized by the CCE program relative to PG&E. For the CCE program, the non-renewable portion of the supply portfolio will be influenced by changes in natural gas and wholesale power prices. The PG&E resource mix includes resources that are influenced by natural gas prices such as utility-owned natural gas fueled power plants, so-FDOOHG ·WROOLQJ DJUHHPHQWV ZLWK independent generators, and certain other contracts that are priced based on an avoided cost formula. The PG&E resource mix also includes energy sources that are not affected by natural gas prices, including UHQHZDEOH UHVRXUFHV DV ZHOO DV 3*(•V K\GUR-electric and nuclear assets. Sensitivity to changes in natural gas and power prices were tested by varying the base case assumptions to create high and low cases. The high case reflects a 50% increase in this input relative to the base case and the low case reflects a 25% decrease relative to the base case. R e n ew a b l e E n e r g y C os t s There can be wide variation in renewable energy costs due to locational factors (wind regime, solar insulation, availability of feedstock for biomass and biogas facilities, etc.), transmission costs, technological changes, federal tax policy, and other factors. ,Q IDFW WKH IHGHUDO LQYHVWPHQW WD[FUHGLW RU ·,7&LV H[SHFWHG WR decrease significantly for projects commencing operations on or after January 1, 2017 † the ITC is expected WR GURS IURP WR EDVHG RQ 3($•V XQGHUVWDQGLQJ ZKLFK FRXOG LPSRVH JHQerally proportionate increases to renewable energy pricing following such a change. Sensitivity to renewable energy cost assumptions was tested by varying the base case costs for renewable power purchase contracts and for the installed costs for renewable generation projects by 25% for the high case and -25% for the low case. The variances were only applied to SVCCE•V FRVW VWUXFWXUH DQG QRW 3*(•V in order to test the impact of potential variation in site-specific renewable projects used by the CCE program. 162 163 164 Draft Silicon Valley Community Choice Energy Technical Study Page 66 Section 6: Sensitivity Analyses C o m m un it y Pa r ti c i p a ti on (S m a ll JPA ) While the base case includes all municipalities as participants in the JPA, a sensitivity was run to examine the impacts of a much smaller program being formed in the region. For purposes of this sensitivity, it was assumed that 25% of the total potential customers are offered service in the CCE and that 15% of these customers elect to opt-out. Adjustments were made to assumed staffing costs to reflect the smaller scale of operations. The long term renewable contract portfolio was adjusted downward on a pro rata basis to reflect the reduced energy requirements. The results of this sensitivity indicate that a viable program could be operated with significantly less than 100% participation of the prospective communities. While not explicitly modeled, a program serving only the four sponsoring partner agencies (representing 68% of the total potential load) would have sufficient scale and be expected to have similar rates as presented in the base case projections. Pe r f e c t S t o r m This sensitivity examines the cumulative effects of adverse changes to all of the key variables to present what could be considered a worst case. The likelihood that all of these variables change in unison is remote; many of the key variables are negatively correlated meaning that increases in one variable would normally be associated with decreases in another. For example, increases in market prices for power should result in decreases in the PG&E surcharges, but for purposes of this sensitivity it was assumed that the PG&E surcharges would also increase. This sensitivity was constructed with the following assumptions: high natural gas/power prices, high renewable energy and low carbon energy costs, high PG&E surcharges, high customer opt-out rates, and low PG&E rates. S e ns i ti vit y R e su lt s The sensitivity analysis produced a range of levelized electric rates for the CCE program and PG&E as shown in the Figure 25.32 When reviewing this figure, the base case outcomes associated with each scenario are represHQWHG E\WKH ·DUURZKHDGV that are positioned along each vertical line † to the extent each line extends above (or below) the arrowhead, this represents the potential for customer rates to be higher (or lower) than the base case outcomes. It should be noted that there is considerable overlap in the range of estimated rates, and while base case estimates show higher rates for the CCE program, any of the CCE Scenarios could potentially result in lower ratepayer costs than under the status quo. The sensitivity analysis for the Community Participation (Small JPA) and Perfect Storm conditions are discussed above but not included in Figure 25 as they are very unlikely to occur and would distort the results presented in the figure. Rate outcomes for all conditions analyzed are included in Table 28 and Figures 26 and 27. 32 The ranges shown in Figure 25 do not include the Small JPA and Perfect Storm sensitivities. 165 Draft Silicon Valley Community Choice Energy Technical Study Section 6: Sensitivity Analyses Page 67 Figure 25: Sensitivity Analysis Range of Levelized Electric Rates The sensitivity to each tested variable is shown in the following table. Natural Gas/Power prices and PG&E Surcharges had the greatest impact on SVCCE rates in Scenarios 1 and 2, while renewable energy costs were an increasingly important driver of SVCCE rates in Scenarios 3. Table 28 provides additional detail regarding potential impacts to SVCCE and PG&E rates that could result under each sensitivity variable. Table 28: Sensitivity Analysis - Levelized Ratepayer Costs (Cents Per KWh) Rate Scenario Base Case High Gas/ Power Low Gas/ Power High R.E. Costs Low R.E. Costs High PG&E Rates Low PG&E Rates High PCIA Low PCIA High Opt Out Low Opt Out High Carbon Free Cost Small JPA Perfect Storm CCE Scenario 1 21.5 22.4 21.0 22.1 20.8 21.5 21.5 22.4 20.5 21.5 21.4 21.7 22.3 23.9 CCE Scenario 2 21.8 22.7 21.4 22.5 21.1 21.8 21.8 22.8 20.8 21.8 21.7 22.0 22.4 24.2 CCE Scenario 3 22.3 23.2 21.8 23.1 21.4 22.3 22.3 23.2 21.3 22.3 22.2 22.4 22.8 24.8 PG&E Bundled 22.3 22.9 21.9 22.3 22.3 23.8 21.6 22.3 22.3 22.3 22.3 22.3 22.3 21.6 The sensitivity results for each SVCCE supply scenario are depicted graphically in the following figures. 18.0 19.0 20.0 21.0 22.0 23.0 24.0 25.0 CCA Scenario 1 CCA Scenario 2 CCA Scenario 3 PG&E BundledCents Per KWh166 167 168 Draft Silicon Valley Community Choice Energy Technical Study Page 70 Section 7: Risk Analysis SECTION 7: RISK ANALYSIS CCE formation is not without risk, and a key element of this Study is highlighting risks that may be faced by the CCE program as well as related risk-mitigation measures. Several of the quantitative impacts associated with key risks have been addressed in Section 6, Sensitivity Analyses. However, there are additional risk elements of which any aspiring CCE program should be aware as well as associated mitigation measures for such risks. In particular, these additional risks include, but are not limited to, the following: Financial risks to SVCCE•V PHPEHU PXQLFLSDOLWies in the unlikely event of CCE failure; Financial risks that may exist in the event that procured energy volumes fall short of or exceed actual customer energy use; Reasonably foreseen legislative and regulatory changes, which may limit a CCE•V DELOLW\WR UHPDLQ competitive with the incumbent utility; Availability of renewable and carbon-free energy supplies required to meet compliance mandates, SVCCE program goals, and customer commitments; and General market volatility and price risk. F i n a n c i a l R i s k s t o S V C C E Mem b e r s In general terms, the prospective financial risks to SVCCE members will be limited to the extent that the JPA DJUHHPHQW FUHDWHV VHSDUDWLRQ DOVR UHIHUUHG WR DV D ·ILUHZDOO EHWZHHQ WKH ILQDQFLDO DVVHWV DQG REOLJDWLRQV of the JPA and those of its individual members. This approach has been effectively employed by both MCE and SCP at the time that each JPA was created, insulating the respective members of each organization from the financial liabilities independently incurred by the JPA (e.g., power purchase agreements, debt, letters of credit and other operating expenditures). For example, if the JPA was to default on a contract obligation, any termination payments would be owed by the JPA and not the individual members, as individual JPA members would not be responsible for the financial commitments of the JPA. From a practical perspective, each member of the JPA would have a relatively small financial exposure, which would be limited to any early-stage contributions and/or expenditures related to the CCE initiative before joining the JPA. After joining the JPA, each participating municipality would be financially insulated via the JPA agreement, and it is anticipated that the JPA would be financially independent during ongoing CCE operations, meaning that the JPA would be responsible for independently demonstrating creditworthiness when entering into power purchase agreements and financial covenants %DVHG RQ 3($•V XQGHUVWDQGLQJ TXDOLILHG OHJDO FRXQVHO ZDV engaged during the formation of each operating, multi-jurisdiction CCE to ensure that the associated JPA agreement created the desired financial protections for its members. Other than relatively small upfront costs/contributions that may be incurred by the JPA members during CCE evaluation and JPA formation and any guarantees that may be offered to support startup, financial obligations of the participating communities would be limited to individual customer impacts in the event of outright CCE failure. In such a scenario, the $100,000 CCE bond is intended to cover the costs of returning customers to PG&E service. However, following an involuntary return to bundled service, CCE customers would be individually required to pay the PG&E Transitional Bundled Commodity Cost (TBCC), which imposes a market-based rate on customers who fail to provide PG&E with six-month advance notice prior to reestablishing PG&E electric service.33 In recent years, the TBCC rate has likely benefited participating customers due to historically low market prices (and the favorable relationship of such prices to PG&(•V generation rates). However, inherent price volatility within the electric power sector could result in relatively high customer costs in the short-term, following an involuntary return to bundled service at a time when market 33 http://www.pge.com/tariffs/tm2/pdf/ELEC_SCHEDS_TBCC.pdf 169 Draft Silicon Valley Community Choice Energy Technical Study Section 7: Risk Analysis Page 71 prices are higher than PG(•V SUHYDLOLQJ JHQHUDWLRQ UDWHV Depending on future market conditions during a time of involuntary customer return to PG&E service, cost impacts during the six-month transition period could be +/-25% (or more, depending on actual market prices) relative to otherwise applicable PG&E rate schedules. In practical terms, the likelihood of this risk materially impacting a SVCCE customer appears to be quite low. In addition to the aforementioned financial risks to the JPA and its respective members, it is also noteworthy that a subset of the CCE Study Partners, including the cities of Sunnyvale, Cupertino and Mountain View as well as Santa Clara County, have entered into a project funding agreement to facilitate CCE program evaluation, formation and implementation † these communities have made certain financial expenditures to provide for the evaluation of prospective CCE formation. PEA also understands that this subset of the CCE Study Partners, as well as other project participants, may choose to make additional contributions for purposes of completing SVCCE•V IRUPDWLYH DQG VWDUW-up activities. At the time of JPA formation, PEA understands that certain CCE Study Partners may request repayment of the noted initial expenditures following successful launch of the SVCCE program and a yet-to-be-defined period of successful operations. Clearly, the repayment of such funding is dependent upon the successful launch and operation of the SVCCE program. For example, if SVCCE fails to launch or discontinues business operations prior to repaying initial funding contributed by certain of the CCE Study Partners, then such Partners run the risk of financial losses equivalent to any amounts expended in advance of such circumstances. With regard to the risk of the CCE Study Partners losing its initial investment in CCE evaluation and formation, failure to launch the SVCCE program represents the primary risk in this regard. Once SVCCE has launched and is serving customers, it is reasonable to assume that the financial contributions that were previously made by certain CCE Study Partners would be paid back within the first five years of SVCCE operation. Based on recent discussions and general enthusiasm related to the SVCCE initiative, it seems reasonable to assume that the SVCCE program will launch as planned, unless market conditions significantly change such that initial SVCCE rates are projected to exceed similar rates charged by PG&E. Under Scenario 2, for example, sensitivity analyses suggest that power costs could increase by 14% or PG&E rates could decrease by 11% (or a related combination of such impacts) before projected SVCCE UDWHV ZRXOG H[FHHG 3*(•V SURMHFWHG UDWHV From a practical perspective, this observation suggests that current operating projections provide considerable safety margins for SVCCE, allowing for a range of market conditions and/or rate changes before rate competitiveness would be FRPSURPLVHG ,W LV QRWHZRUWK\WKDW 3*(•V UDWHV ZLOO UHPDLQ XQNQRZQ XQWLO -DQXDU\DQG SRZHU FRVWV ZRQ•W EH NQRwn until SVCCE issues a related solicitation for such products, which is expected to occur in early 2016. In the event that actual PG&E rate changes and/or proposed power prices fall outside of the aforementioned safety margins, SVCCE would likely defer program launch and cease incurring startup expenses until projected operations improve, potentially jeopardizing or delaying the reimbursement of funding initially provided by certain of the CCE Study Partners. D e v i a t i ons b e t wee n A c t u a l E n e r g y Us e a nd C on t r a c t e d Pu r c h a s e s Deviations between actual customer energy use and contracted energy purchases are inevitable. For example, weather variation may impose meaningful day-to-day variances in expected customer energy use, which results in the potential for ongoing imbalances between procured energy volumes and actual electric energy consumption by SVCCE•V FXVWRPHU EDVH. To the extent that such imbalances exist, the CCE may be required to make market purchases during unexpected price spikes and/or sell off excess energy volumes at times when prices are relatively low (when compared to the price paid for such energy), which could impose adverse financial impacts on the CCE program. Again, this is an inevitable risk that is assumed by all energy market participants, but prudent planning and procurement practices can be utilized by the CCE to manage 170 Draft Silicon Valley Community Choice Energy Technical Study Page 72 Section 7: Risk Analysis VXFK ULVN WR DFFHSWDEOH OHYHOV ,Q SDUWLFXODU ·ODGGHUHG SURFXUHPHQW VWUDWHJLHV FDQ EH KLJKO\HIIHFWLYH LQ mitigating such risks † this procurement strategy is designed to promote increased cost/rate certainty during the upcoming 12-month operating period by securing 90-100% of the CCE•V SURMHFWHG HQHUJ\UHTXLUHPHQWV during this period of time. Beyond the 12-month operating horizon, an increasing proportion of the CCE•V anticipated energy requirements DUH OHIW ·RSHQ L H DUH QRW DGGUHVVHG YLD FRQWUDFWXDO FRPPLWPHQWV WR avoid financial commitments based on reduced planning certainty. For example, the CCE program may decide that it is acceptable to take on market price risk associated with 5% of its expected energy requirements over the upcoming 12-month operating period † this strategy would create cost certainty for a significant portion of the CCE•V H[SHFWHG HQHUJ\UHTXLUHPHQWV DOORZLQJ WKH CCE to set rates in consideration of such costs with minimal financial/budgetary risk. For months 13-24, the CCE would reduce forward supply commitments to a level approximating 80-90% of expectations; for months 25-36, the CCE would further reduce forward supply commitments to a level approximating 70-80% of expectations. Forward procurement commitments would FRQWLQXH WR ·IDOO GRZQ WKH ODGGHU LQ VXEVHTXHQW PRQWKV EXW VXFK RSHQ positions are ultimately filled with time. It is also noteworthy that such percentages could always be adjusted in consideration of prevailing market prices and the CCE•V RYHUDOO ULVN WROHUDQFH This procurement strategy avoids the prospect of over-procurement and minimizes the prospect of surplus energy sales while also allowing the CCE program to take advantage of favorable procurement opportunities that may come about with time. During early-stage CCE operations, this strategy is particularly useful since the CCE is unlikely to know exact customer participation levels. Over time, as the CCE•V FXVWRPHU EDVH becomes more stable/predictable, it will become less challenging to predict customer usage patterns. Furthermore, a laddered procurement strategy allows the CCE•V SRUWIROLR FRPSRVLWLRQ WR HYROYH RYHU WLPH as opposed to committing to a specific resource mix that would only be minimally adjustable (subject to potential adverse economic consequences) until related power supply agreements had expired. L e g i s l a t i v e a nd R e g u l a t o r y R i s k &DOLIRUQLD•VRSHUDWLQJ CCEs can attest to the challenges presented by anti-CCE legislation † a range of tactics have been employed over time, pre-GDWLQJ 0&(•V ODXQFK LQ 0D\DQG UHVXUIDFLQJ WKHUHDIWHU LQ YDULRXV forms. Ongoing issues continue to arise with regard to proposed legislation designed to assign/shift costs for purposes of competitively disadvantaging CCE programs and/or limit the autonomy of CCE programs, so that such programs appear more similar to their investor-owned counterparts. Recently, SB 350 and AB 1110 presented such issues. +RZHYHU &DOLIRUQLD•V RSHUDWLQJ CCEs were able to address many of the potentially detrimental changes included within these bills through effective lobbying and technical support. &DOLIRUQLD•V IOUs regularly rely on professional lobbyists to promote their respective interests within the California legislature, and CCEs have successfully employed similar tactics to represent their own interests, which often differ from those of their investor-owned counterparts. Use of lobbyists within proximity to the State Capitol also mitigates logistical challenges that may be encountered when addressing time-sensitive issues that require on-site meeting participation and collaboration. CCEV KDYH DOVR HQMR\HG VLPLODU VXFFHVV LQ &DOLIRUQLD•V UHJXODWRU\ arena by utilizing the expertise of specialized regulatory support, including qualified regulatory counsel and analysts, who have deep and long- standing familiarity with a broad range of regulatory proceedings, assigned commissioners, judges and support staff within jurisdictional agencies. Because certain proceedings have the potential to directly affect the formation and ongoing operation of CCE programs, it is critically important to retain such expertise for purposes of representing the CCEs interests, particularly if the CCE has not yet hired internal regulatory counsel and/or staff. Over time, the CCE program may choose to scale its internal regulatory staffing in consideration of the level of work required to achieve successful regulatory representation and desired outcomes. 171 Draft Silicon Valley Community Choice Energy Technical Study Section 7: Risk Analysis Page 73 Regarding recent legislation, on October 7, 2015, Governor Brown signed Senate Bill 350, the Clean Energy and Pollution Reduction Act of 2015, enacting pertinent clean energy mandates reflected in this legislation. In particular, SB 350 increases &DOLIRUQLD•V 536 WR E\DPRQJVW RWKHU FOHDQ-energy initiatives. Many details regarding implementation of SB 350 will be developed over time with oversight by applicable regulatory agencies. With regard to other relevant changes that have been created by SB 350, CCEs should be aware of the following: x Costs associated with the integration of new renewable infrastructure may be off-set by a CCE if it can demonstrate to the CPUC that it has already provided equivalent resources [Sections 454.51(d) and 454.52(c)]; x CCEs will be required to submit Integrated Resource Plans to the CPUC for certification while retaining the governing authority and procurement autonomy administered by their respective governing boards [Section 454.52(b)(3)]; x The CPUC is now responsible for ensuring that: (1) IOU bundled customers do not incur any cost increases as a result of customers participating in CCE service options, and (2) CCE customers do not experience any cost increases as a result of IOU cost allocation that is not directly related to such CCE customers (Sections 365.2 and 366.3); x Beginning in 2021, CCEs must have at least 65% of their RPS procurement under long-term contracts of 10 years or more [Section 399.13(b)]; and x CCE energy efficiency programs will be able to count towards statewide energy efficiency targets [Sections 25310(d)(6) and 25310(d)(8)]. In aggregate, the CCE-specific changes reflected in SB 350 are generally positive, providing for ongoing autonomy with regard to resource planning and procurement. CCEs must be aware, however, of the long- term contracting requirement associated with renewable energy procurement. This is not expected to present issues for SVCCE, but planning and procurement efforts will need to consider this requirement during ongoing operation of the CCE program. AB 1110, which is now a two-year bill, was primarily focused on the addition of GHG emission disclosures within the Power Content Label. During discussion in the recent legislative session, CCE interests were generally concerned that the emissions methodology reflected in the bill was designed in a manner that was not necessarily consistent with retail-level emissions reporting conventions used throughout the electric utility industry and also appeared to diminish the environmental value of certain clean energy products. On September 8, 2015, AB 1110 was ordered to the inactive file at the request of Senator Wolk.34 With this direction in mind, AB 1110 is no longer an issue in the current legislative session. However, PEA recommends that the CCE Study Partners VKRXOG FRQWLQXH WR PRQLWRU WKH OHJLVODWXUH•V LQWHUHVW LQ SURPRWLQJ FHUWDLQ UHSRUWLQJ changes reflected in AB 1110, as such changes could narrow the potential field of cost-effective supply options that could be pursued by SVCCE at some point in the future. The AB 1110 GHG emissions reporting methodology may also present methodological conflicts with other programs, such as The Climate Registry, which may be of interest to SVCCE at some point in the future. Another piece of pending legislation that could pose direct and indirect impacts on CCE programs is SB 286 (Hertzberg). SB 286 was originally introduced during the 2015 legislative session (has now been converted into a two-year bill) with the goal of increasing the direct access participatory cap by approximately 33%. In its current form, SB 286 suggests that new direct access customers would be required to contract for 100% 34 AB 1110 bill history: http://leginfo.legislature.ca.gov/faces/billHistoryClient.xhtml?bill_id=201520160AB1110 . 172 Draft Silicon Valley Community Choice Energy Technical Study Page 74 Section 7: Risk Analysis renewable energy. If passed during the 2016 legislative session, SB 286 could either spark additional renewable development, which could keep prices stable, or push renewable prices upward due to the increased demand. Additionally, raising the direct access cap could put more pressure on CCE programs to offer even more price competitive products to retain large commercial and industrial customers. Regulatory risks include the potential for utility generation costs to be shifted to non-bypassable and delivery charges. Examples include: 1) the Cost Allocation Mechanism ·&$0 , under which the costs of certain generation commitments made by the investor owned utilities deemed necessary for grid reliability or to support other state policy, are allocated to non-bundled (CCE and direct access) customers; and 2) the PCIA as previously discussed. CAM is a mechanism that allows investor owned utilities to impose a portion of the costs associated with their power purchases onto CCE customers, even though these purchases are for fossil fuel resources with prices that are often above current market levels. In theory, the goal of CAM is to promote grid reliability and should only be applied to resources that contribute in that regard; in practical terms, the investor owned utilities have obtained CPUC-approved CAM treatment for many types of generating resources. Bundled, CCE, and direct DFFHVV FXVWRPHUV SD\IRU &$0 LQ WKH IRUP RI WKH1HZ 6\VWHP *HQHUDWLRQ &KDUJH ·16*&The NSGC imposes costs on CCE customers that often seem to be duplicative in light of long-term capacity commitments that have already been made by CCEs in the form of various power purchase agreements (which can include capacity attributes as an element of the purchased product). In other words, the present CAM methodology does not appear to adequately reflect the contribution being made by CCEs in terms of promoting capacity buildout within California•V HQHUJ\PDUNHW and generally undermines CCE procurement autonomy through the imposition of costs that are not associated with contracts voluntarily entered into by the CCE. One of the only tangible benefits realized by CCE•V XQGHU WKH FXUUHQW CAM rules is an offsetting capacity allocation, which slightly reduces monthly resource adequacy requirements of the CCE entity. As previously noted, the passage of SB 350 requires that CCEs have at least 65% of applicable RPS procurement under long-term contracts, and existing CCEs have already demonstrated a track record of long term contracting notwithstanding the pending requirements of SB 350. Such contracts typically confer capacity benefits associated with the contracted resources, which could result in diminished value of CAM capacity allocations, as many CCEs would have already procured a significant portion of applicable capacity requirements through requisite renewable energy contracting efforts † stated somewhat differently, the CAM charges imposed on CCE customers would result in little capacity value for CCE customers due to the fact that many CCEs would have already arranged for such capacity under requisite long-term contract arrangements. Another significant regulatory risk relates to changes that may occur with regard to the CCE Bond amount. Currently, the $100,000 bond amount is quite manageable for aspiring CCE initiatives, but this could change dramatically in the event that a larger bond amount, based on market conditions at the time of an involuntary return of customers to bundled service, is established at some point in the future. PEA recommends that the CCE Study Partners actively monitor and participate in, as necessary, related regulatory proceedings to ensure that this item does not become a barrier for CCE formation or ongoing operation. As previously noted, retention of an experienced lobbyist and qualified regulatory expertise will serve to manage and mitigate the aforementioned risks. Av a i l a b ilit y o f R e q u i s it e R e n ew a b l e a nd C a r bon -F r ee E n e r g y S upp li e s &DOLIRUQLD•V UHFHQW DGRSWLRQ of a 50% RPS has prompted various questions regarding the sufficiency of renewable generating capacity that may be available to support compliance with such mandates. In particular, both new and existing CCEs, which will be subject to prevailing RPS procurement mandates, UHSUHVHQW D JURZLQJ SRRO RI UHQHZDEOH HQHUJ\EX\HUV WKDW ZLOO EH ·FRPSHWLQJ IRU UHTXLVLWH LQ-state resources. While this is certainly a legitimate concern, particularly when considering that the potential for CCE 173 Draft Silicon Valley Community Choice Energy Technical Study Section 7: Risk Analysis Page 75 expansion throughout California seems quite significant, it is highly unlikely that any CCE buyer would be unable to meet applicable procurement mandates during the ten-year planning horizon. To date, renewable energy contracting opportunities within California have been abundant, providing interested buyers with cost- competitive procurement opportunities well in excess of compliance mandates and voluntary renewable energy procurement targets that have been established by certain CCEs. Furthermore, to the extent that additional CCE SURJUDPV FRQWLQXH WR IRUP &DOLIRUQLD•V ODUJHVW EX\HUV RI UHQHZDEOH HQHUJ\UHSUHVHQWHG E\ the three investor-owned utilities, will have diminished renewable energy procurement obligations as a result of decreasing retail sales. Certainly, the potential exists for increased supply costs as additional CCE buyers compete for available renewable projects, but the general availability of such projects does not seem to be a significant issue that will face SVCCE over the ten-year planning horizon. It is also reasonable to assume that California-based project developers will be competing for buyers in the sense that prospective renewable development opportunities (i.e., potential renewable generating capacity) may actually exceed statewide demand. This cirFXPVWDQFH KDV RFFXUUHG LQ WKH SDVW SDUWLFXODUO\ZKHQ &DOLIRUQLD•V ODUJHVW UHQHZDEOH HQHUJ\ buyers, the IOUs, have met applicable renewable energy procurement targets † in these instances, project GHYHORSHUV DUH IRUFHG WR ·FRPSHWH IRU RWKHU EX\HUV LQFOXGing CCEs, which have benefited from very favorable pricing for both short- and long-term transactions. Additionally, as the operational and future CCE•V VWULYH WR PHHW KLJK carbon-free energy targets, there is some uncertainty around the availability of hydroelectric generation resources within California and throughout the Pacific Northwest to meet such goals. Outside of renewable energy resources, hydroelectric generation is the lowest cost means of meeting carbon-free objectives (keeping in mind that nuclear generation will be excluded from SVCCE•V VXSSO\SRUWIROLR) but also comes with certain variability in supply. Given the variability of such resources (i.e., wet versus dry year) and unpredictability of the day-to-day energy deliveries, there is risk in achieving carbon content goals. There is also a cost risk associated with the transmission of out-of-state hydroelectric generation into California during certain times of the year when California energy buyers are seeking to import peak hydro season production † this congestion risk could add significant costs to contracted hydroelectric power. To the extent that necessary hydroelectric power supply is not available, the CCE program may choose to incorporate additional renewable energy supply, likely at an increased cost, to ensure that emission reduction commitments can be satisfied. M a r k e t Vo l a tilit y a nd P r i c e R i s k Wholesale energy markets are subject to sudden and significant volatility, resulting from myriad factors, including but not limited to the following: weather, natural disasters, infrastructure outages, legislation and implementing regulations, and natural gas storage levels. Over the past 24 months (or longer), wholesale energy prices have fallen to near-historic lows, providing a favorable environment for buyers of electric energy. An abundance of domestic natural gas supply, particularly shale gas, and strong storage levels have also suppressed electric energy pricing, which will likely promote the continued trend of relatively low prices for the foreseeable future. However, unexpected circumstances can impose abrupt changes to available pricing, which necessitates a thoughtful, disciplined approach to managing such risk. The following figure, provided by the CAISO, illustrates historic volatility in the wholesale electricity market, including a nearly 40% reduction in such prices over the past 24 months.35 35 California ISO Q2 2015 Report on Market Issues and Performance, August 17, 2015. 174 Draft Silicon Valley Community Choice Energy Technical Study Page 76 Section 7: Risk Analysis Figure 29: Historical Wholesale Electricity Price Curve As previously described, a laddered procurement strategy will serve to mitigate wholesale pricing impacts at any single point in time. Much like dollar cost averaging in the financial sector, laddered procurement strategies serve to mask the impacts of periodic price spikes and troughs by blending the financial impacts associated with such changes through a temporally diversified supply portfolio. For example, Table 29 reflects typical guidelines associated with a laddered procurement strategy † such strategies generally attempt to balance the interests of near-term planning and budgetary certainty while moderating market price risks at any single point in time. Based on the declining percentages reflected in Table 29, this balance could be reasonably achieved while allowing for the inclusion of other, future contracting opportunities as well as planned efficiency and demand-side impacts. Such strategies have been successfully implemented by other CCE programs and are generally recognized as a prudent planning/procurement strategy. Note that the percentages reflected in Table 29 PD\YDU\LQ FRQVLGHUDWLRQ RI WKH EX\HU•V unique preferences and tolerance for risk. Table 29: Indicative Contracting Guidelines under a Laddered Procurement Strategy Time Horizon Contracting Guideline (Contractual Commitments/Total Energy Need) Current Year 80% to 100% Year 2 70% to 100% Year 3 60% to 95% Year 4 and Beyond Up to 70% This procurement strategy should also create a certain level of symmetry with market impacts that would also affect incremental procurement completed by the incumbent utility. Ultimately, there is no mitigation tactic that could completely insulate the CCE from market price risk, but a diversified supply portfolio, in terms of transaction timing, fuel sources and contract term lengths, will minimize such risks over time. 175 Draft Silicon Valley Community Choice Energy Technical Study Section 8: CCE Formation Activities Page 77 SECTION 8: CCE FORMATION ACTIVITIES This section provides a high level summary of the main steps involved in forming a CCE program that culminates in the provision of service to enrolled customers. Key implementation activities include those related to 1) CCE entity formation; 2) regulatory requirements; 3) procurement; 4) financing; 5) organization; and 6) customer noticing. Completion of these activities is reflected in the SWXG\•V VWDUWXS FRVW HVWLPDWHV CCE E n t it y F o r m a ti on Unless the municipal organization that will legally register as the CCE entity already exists, it must be legally established. Municipalities electing to offer or allow others to offer CCE service within their jurisdiction must do so by ordinance. As anticipated for SVCCE, a joint power authority ·-3$WKH PHPEHUV RI ZKLFK ZLOO include certain or all municipal jurisdictions currently represented amongst the CCE Study Partners, will be formed via a related agreement amongst the participating municipalities. Specific examples of applicable JPA agreements are available for currently operating CCE programs, including MCE and SCP, which were IRUPHG XQGHU WKLV MRLQW VWUXFWXUH %DVHG RQ 3($•V XQGHUVWDQGLQJ VSHFLILF GHWDLOV UHODWHG WR SVCCE•V -3$ agreement are being developed. R e g u l a t o r y R e q u i r eme n t s Before aggregating customers, the CCE program must meet certain requirements set forth by the CPUC. In the case of SVCCE, an Implementation Plan must be adopted by the joint powers authority, and that Implementation Plan must be submitted to the CPUC. The Implementation Plan must include the following: x An organizational structure of the program, its operations, and its funding; x Ratesetting and other costs to participants; x Wrovisions for disclosure and due process in setting rates and allocating costs among participants; x The methods for entering and terminating agreements with other entities; x The rights and responsibilities of program participants, including, but not limited to, consumer protection procedures, credit issues, and shutoff procedures; x Termination of the program; and x A description of the third parties that will be supplying electricity under the program, including, but not limited to, information about financial, technical, and operational capabilities. A Statement of Intent must be included with the Implementation Plan that provides for: x Universal access x Reliability x Equitable treatment of all classes of customers x Any requirements established by law or the CPUC concerning aggregated service. The CPUC has ninety days to complete a review and certify the Implementation Plan though previous Implementation Plan reviews completed on behalf of other California CCE programs have required far less time. Following certification of the Implementation Plan, the CCE entity must submit a registration packet to the CPUC, which includes: x An executed service agreement with PG&E, which may require a security deposit; and 176 Draft Silicon Valley Community Choice Energy Technical Study Page 78 Section 8: CCE Formation Activities x A bond or evidence of sufficient insurance to cover any reentry fees that may be imposed against it by the CPUC for involuntarily returning customers to PG&E service. As previously noted, the current CCE bond amount is $100,000. The CCE SURJUDP ZRXOG EH UHTXLUHG WR SDUWLFLSDWH LQ WKH &38&•V UHVRXUFH DGHTXDF\SURJUDP EHIRUH commencing service to customers by providing load forecasts and advance demonstration of resource adequacy compliance. More specifically, a start-up CCE program would be required to file a formal load forecast with the CEC upon execution of a primary supply contract, which triggers a 100% commitment to program launch. P r o c u r eme n t Power supplies must be secured several months in advance of commencing service. Power purchase agreements with one or more power suppliers would be negotiated, typically following a competitive selection process. Services that are required include provision of energy, capacity, renewable energy and scheduling coordination. Once a firm commitment to offering CCE service is made, typically through execution of power supply contracts, the CCE should provide its inaugural load forecast to the California Energy Commission to initiate determination of the applicable resource adequacy requirements (i.e., capacity) for the first year of operation. F i n a n c i n g Funding must be obtained to cover start-up activities and working capital needs. Start-up funding would be secured early in the implementation process as these funds would be needed to conduct the critical activities leading up to service commencement. Working capital lender commitments should be secured well in advance, but actual funding need not occur until near the time that service begins. O r g a n i z a t i on Initial staff positions would be filled several months in advance of service commencement to conduct the implementation process. Initially, internal staff of the CCE program may be relatively small but this would likely change in the event that the CCE determines to insource various administrative and operational responsibilities and/or develops and administers new programs for its customers. Contracts with other service providers, such as for data management services, would be negotiated and put into effect well in advance of service commencement. C us t o me r N o t i c e s Customers must be provided notices regarding their pending enrollment in the CCE program. Such notices must contain program terms and conditions as well as opt-out instructions and must be sent to prospective customers at least twice within the sixty-day period immediately preceding automatic enrollment. These QRWLFHV DUH UHIHUUHG WR DV ·SUH-HQUROOPHQW QRWLFHV 7ZR DGGLWLRQDO ·SRVW-HQUROOPHQW QRWLFHV PXVW EH provided within the sixty-day period following customer enrollment during the statutory opt-out period. R a t e s e t ti n g a nd P r e li m i n a r y P r o g r a m D e v e l op me n t As a California CCE, SVCCE would have independent ratesetting authority with regard to the electric generation charges imposed on its customers. Prior to service commencement, SVCCE would need to establish initial customer generation rates for each of the customer groups represented in its first operating phase or for all prospective customers within the CCE•V SURVSHFWLYH service territory. SVCCE may decide to create a schedule of customer generation rates that generally resembles the current rate options offered by PG&E. 177 Draft Silicon Valley Community Choice Energy Technical Study Section 8: CCE Formation Activities Page 79 This practice would facilitate customer rate comparisons and should avoid confusion that may occur if customers were to be transitioned to dissimilar tariff options. SVCCE would need to establish a schedule for ongoing rate updates/changes for future customer phases and ongoing operations. SVCCE may also choose to offer certain customer-focused programV VXFK DV 1HW (QHUJ\0HWHULQJ ·1 (0 voluntary green pricing and/or FIT programs, at the time of service commencement. To the extent that SVCCE intends to offer such programs, specific terms and conditions of service would need to be developed in advance of service commencement. 178 Draft Silicon Valley Community Choice Energy Technical Study Page 80 Section 9: Evaluation and Recommendations SECTION 9: EVALUATION AND RECOMMENDATIONS This section provides an overall assessment of the feasibility for forming a CCE program serving communities of the CCE Study Partners DQG SURYLGHV 3($•V UHFRPPHQGDWLRQV LQ WKH HYHQW D GHFLVLRQ LV PDGH WR SURFHHG with development of the SVCCE program. 3($•V DQDO\VLV suggests that SVCCE could provide significant benefits † both economic and environmental † which could be accomplished under certain prospective operating scenarios with customer rates that are competitive, if not lower than, current rate projections for PG&E. Under a reasonable range of sensitivity assumptions, the analysis shows that customer rates are projected to range from approximately 21 to 23 cents per kWh, on a ten-year levelized cost basis, while PG&E rates are projected to range from 22 to 24 cents per kWh on a levelized basis over this same period of time. Under base case assumptions, CCE program rates are projected to range from 21.5 cents per kWh to 22.3 cents per kWh, depending upon the ultimate CCE program resource mix. 3*(•V generation rate is projected to be 22.3 cents per kWh, creating the potential for customer savings under two of the three supply scenarios. Table 30 shows projected levelized electric rates and typical residential monthly electric bills under the base case assumptions. Table 30: Summary of Ratepayer Impacts Ratepayer Impact Scenario 1 Scenario 2 Scenario 3 PG&E Levelized Electric Rate (Cents/KWh) 21.5 21.8 22.3 22.3 Typical Residential Bill ($/Month)36 $112 $114 $116 $116 It should be noted that there is considerable overlap in the range of estimated rates under the various sensitivity scenarios described in this Study, and while base case estimates generally show highly competitive rates for the CCE program, it is anticipated that Scenarios 1 and 2 are most likely to generate customer rate savings while Scenario 3 is most likely to result in general cost equivalency over time. With regard to GHG emissions impacts, the ultimate resource mix identified by the CCE program will dictate actual GHG emissions impacts created by SVCCE operation. Depending upon resource choices made by the CCE program, potential GHG emissions may vary widely relative to PG&E. For example, under Scenario 1, SVCCE should assume zero electric power sector GHG emissions impacts within communities of the CCE Study Partners. Scenarios 2 and 3 are both expected to create significant GHG emissions reductions through the procurement of significant quantities of renewable and additional carbon-free energy. Table 31 summarizes projected GHG emissions impacts for each of the modeled supply scenarios. 36 Average monthly residential electricity consumption within communities of the CCE Study Partners is approximately 510 kWh. 179 Draft Silicon Valley Community Choice Energy Technical Study Section 9: Evaluation and Recommendations Page 81 Table 31: GHG Emissions Impacts (Ten Year Average) GHG Impact Scenario 1 Scenario 2 Scenario 3 Annual Change in GHG Emissions (Tons CO2/Year) Zero -82,659 -310,504 Change in Electric Sector CO2 Emissions within Communities of the CCE Study Partners (%) Zero -20% -73% Projected SVCCE Portfolio Emissions Factor (metric tons/MWh) 0.128 0.103 0.034 Projected PG&E Portfolio Emissions Factor (metric tons/MWh) 0.128 0.128 0.128 Figure 30 illustrate projected GHG emissions from CCE program customer under the status quo as well as each of the prospective SVCCE supply scenarios. When reviewing Figure 30, note that the sharp increase in HPLVVLRQV EHWZHHQ \HDU RQH DQG \HDU WKUHH LV GLUHFWO\UHODWHG WR 69&&(•s phased customer enrollment schedule † during this three-year period, total emissions are expected to increase as customers are added to the SVCCE program. Following full enrollment in year three, SVCCE portfolio emissions gradually decline over time as increased quantities of carbon-free energy sources are increasingly reflected in the overall SVCCE resource mix. Note that the projected GHG emissions trend associated with Scenario 1 coincides with the PG&E reference line, as there are zero assumed GHG emissions reductions under this planning scenario. Figure 30: Projected GHG Emissions The potential for local generation investment arising from the CCE program appears to offer significant benefits to the local economy. Again, resource decisions will impact the degree to which generation investments yield local benefits as indicated through the analysis of local economic impact associated with the representative supply scenarios. Compared to some other areas in the state, communities of the CCE Study Partners are not the best resource areas for solar and wind production, and local projects of this type will tend to have higher costs than projects sited in prime resource areas. Tradeoffs also exist between minimizing ratepayer costs in the short run and expanding use of renewable energy due to the cost premiums that currently exist for renewable energy. Decisions made during the implementation process and during the life - 100,000 200,000 300,000 400,000 500,000 600,000 1 2 3 4 5 6 7 8 9 10CO2 Emissions (Metric Tons)Year PG&E/SVCCE Scenario 1 SVCCE Scenario 2 SVCCE Scenario 3 180 Draft Silicon Valley Community Choice Energy Technical Study Page 82 Section 9: Evaluation and Recommendations of the CCE program will determine how these considerations are balanced. PEA recommends that considerable thought be given upfront to the ultimate goals of the CCE program so that clear objectives are established, giving those responsible for administering the CCE program the opportunity to develop and execute resource management and procurement plans that meet objectives of the CCE Study Partners. ,Q VXPPDU\LW LV 3($•V RSLQLon that, based on currently observed wholesale market conditions, anticipated PG&E electric rates and certain of the supply scenarios evaluated in this Study, amongst various other considerations, a CCE program serving customers within communities of the CCE Study Partners could offer both economic (i.e., positive economic development impacts and overall cost savings for customers of the CCE program) and environmental benefits during initial program operations and, potentially, throughout the ten- year study period. As previously noted, GXH WR WKH G\QDPLF QDWXUH RI &DOLIRUQLD•V HQHUJ\PDUNHWV particularly market prices which are subject to frequent changes, the SVCCE Partnership should confirm that the assumptions reflected in this Study generally align with future market conditions (observed at the time of any decision by the SVCCE Partnership to move forward) to promote the achievement of early-stage SVCCE operations that generally align with the operating projections reflected in this Study † to the extent that future market price benchmarks materially differ from any of the assumptions noted in this Study, PEA recommends updating pertinent operating projections to ensure well-informed decision making and prudent action related to SVCCE program formation. 181 Draft Silicon Valley Community Choice Energy Technical Study Appendix A: SVCCE Pro Forma Analyses Page 83 APPENDIX A: SVCCE PRO FORMA ANALYSES 182 SILICON VALLEY COMMUNITY CHOICE ENERGYFINANCIAL PRO FORMA ANALYSISSCENARIO 1CATEGORYYEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10I. CUSTOMER ACCOUNTS:RESIDENTIAL (E-1)61,781124,179 187,200 188,136 189,076190,022190,972191,927192,886193,851SMALL COMMERCIAL (A-1)5,08510,22115,40915,48615,56315,64115,71915,79815,87715,956SMALL COMMERCIAL (A-6)3326671,0061,0111,0161,0211,0261,0321,0371,042MEDIUM COMMERCIAL (A-10)7161,4392,1692,1802,1912,2022,2132,2242,2352,247LARGE COMMERCIAL (E-19)3316651,0021,0071,0121,0171,0221,0271,0321,037INDUSTRIAL (E-20)12243737373738383838STREET LIGHTING AND TRAFFIC CONTROL (LS-3)4529081,3691,3761,3831,3901,3971,4041,4111,418AGRICULTURAL (AG-1B, AG-4A, AG-4B, AG-5A, AG-5B, AG-5C)267538810814819823827831835839SUBTOTAL - CUSTOMER ACCOUNTS68,976138,642209,003210,048211,098212,153213,214214,280215,352216,428II. LOAD REQUIREMENTS (KWH):RESIDENTIAL (E-1)379,302,235 762,397,4931,149,314,221 1,155,060,792 1,160,836,096 1,166,640,276 1,172,473,478 1,178,335,845 1,184,227,524 1,190,148,662SMALL COMMERCIAL (A-1)103,830,975 208,700,259 314,615,641 316,188,719 317,769,663 319,358,511 320,955,304 322,560,080 324,172,881 325,793,745SMALL COMMERCIAL (A-6)15,589,202 31,334,295 47,236,450 47,472,633 47,709,996 47,948,546 48,188,289 48,429,230 48,671,376 48,914,733MEDIUM COMMERCIAL (A-10)161,290,281 324,193,466 488,721,650 491,165,258 493,621,084 496,089,190 498,569,636 501,062,484 503,567,796 506,085,635LARGE COMMERCIAL (E-19)226,157,453 454,576,480 685,274,044 688,700,414 692,143,916 695,604,636 699,082,659 702,578,072 706,090,963 709,621,418INDUSTRIAL (E-20)213,906,622 429,952,310 648,153,107 651,393,872 654,650,841 657,924,096 661,213,716 664,519,785 667,842,384 671,181,596STREET LIGHTING AND TRAFFIC CONTROL (LS-3)5,830,06311,718,427 17,665,529 17,753,857 17,842,626 17,931,839 18,021,498 18,111,606 18,202,164 18,293,175AGRICULTURAL (AG-1B, AG-4A, AG-4B, AG-5A, AG-5B, AG-5C)18,032,203 36,244,729 54,638,929 54,912,124 55,186,684 55,462,618 55,739,931 56,018,630 56,298,723 56,580,217SUBTOTAL - LOAD REQUIREMENTS1,123,939,035 2,259,117,460 3,405,619,571 3,422,647,669 3,439,760,907 3,456,959,711 3,474,244,510 3,491,615,733 3,509,073,811 3,526,619,180III. CCA OPERATING COSTS ($)SHORT TERM MARKET PURCHASES$5,041,013$10,132,991 $14,681,238 $14,891,117 $15,310,728 $15,848,723 $16,237,063 $16,791,157 $17,023,403 $17,414,879TERM CONTRACT PURCHASES$12,703,352 $61,538,738 $90,598,285$120,270,043 $122,099,085 $124,231,022 $142,640,040 $143,685,314 $150,230,703 $150,904,675SHORT TERM RENEWABLE MARKET PURCHASES AND RECS$24,965,932 $23,699,137 $34,635,089 $16,805,807 $21,442,193 $26,684,873 $16,084,761 $23,234,929 $24,503,443 $31,730,964SHORT TERM CARBON FREE MARKET PURCHASES$13,777,449 $31,618,914 $53,529,156 $58,123,045 $59,786,581 $61,774,017 $63,729,119 $65,508,621 $65,957,309 $66,808,386ANCILLARY SERVICES AND CAISO CHARGES$3,405,692 $7,075,827$10,997,945 $11,428,579 $11,866,795 $12,334,026 $12,821,715 $13,326,878 $13,812,781 $14,335,558RESOURCE ADEQUACY CAPACITY$5,570,842 $9,270,545$13,329,099 $13,009,335 $13,391,766 $13,788,938 $13,812,953 $14,402,178 $14,745,455 $15,381,372STAFF AND OTHER OPERATIONS COSTS$7,169,346 $8,517,394 $9,928,752$10,146,128 $10,368,322 $10,595,445 $10,827,606 $11,064,918 $11,307,498 $11,555,463BILLING AND DATA MANAGEMENT$1,622,317 $3,358,684 $5,215,112 $5,398,424 $5,588,178 $5,784,603 $5,987,931 $6,198,407 $6,416,281 $6,641,814UNCOLLECTIBLES EXPENSE$384,599 $789,381$1,177,893 $1,263,682 $1,312,588 $1,355,208 $1,410,706 $1,471,062 $1,519,984 $1,573,866STARTUP FINANCING$2,663,926 $2,663,926 $2,663,926 $2,663,926 $2,663,926$0$0$0$0$0CCA BOND CARRYING COST$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500SUBTOTAL - CCA OPERATING COSTS$77,305,968$158,667,037 $236,757,995 $254,001,584 $263,831,662 $272,398,355 $283,553,394 $295,684,964 $305,518,358 $316,348,477IV. REVENUES FROM GREEN PREMIUM AND MARKET SALES ($)GREEN PRICING PREMIUM271,812$ 562,733$ 873,770$ 886,393$ 890,614$ 894,036$ 896,599$ 898,237$ 898,882$ 898,463$ MARKET SALES$0$0$0$0$0$0$0$0$0$0V. CONTRIBUTION TO PROGRAM RESERVES ($)$3,092,239 $6,346,681 $9,470,320$10,160,063 $10,553,266 $10,895,934 $11,342,136 $11,827,399 $12,220,734 $12,653,939VI. CCA REVENUE REQUIREMENT ($)$80,126,394$164,450,985 $245,354,545 $263,275,255 $273,494,314 $282,400,254 $293,998,932 $306,614,126 $316,840,210 $328,103,953CCA PROGRAM AVERAGE RATE (CENTS/KWH)7.1 7.3 7.2 7.7 8.0 8.2 8.5 8.8 9.0 9.3 PG&E AVERAGE GENERATION COST (CENTS/KWH)9.6 9.7 10.1 10.5 10.7 10.9 11.3 11.6 11.9 12.3 VII. PG&E CCA CUSTOMER SURCHARGES ($)POWER CHARGE INDIFFERENCE ADJUSTMENT$17,176,539 $34,339,259 $57,624,201 $59,979,592 $68,846,649 $71,301,137 $73,395,868 $72,904,287 $76,084,978 $75,601,919FRANCHISE FEE SURCHARGE$807,311$1,645,165 $2,566,976 $2,677,997 $2,765,271 $2,826,865 $2,939,449 $3,028,912 $3,132,039 $3,233,921SUBTOTAL - PG&E CCA CUSTOMER SURCHARGES17,983,851$ 35,984,424$ 60,191,178$ 62,657,588$ 71,611,920$ 74,128,002$ 76,335,317$ 75,933,200$ 79,217,017$ 78,835,840$ VIII. CCA REVENUE REQUIREMENT PLUS PG&E CCA CUSTOMER SURCHARGES$98,110,245$200,435,409 $305,545,722 $325,932,843 $345,106,235 $356,528,255 $370,334,248 $382,547,326 $396,057,227 $406,939,792IX. REVENUE AT PG&E GENERATION RATES$107,931,990 $219,947,272 $343,187,142 $358,029,788 $369,697,818 $377,932,408 $392,984,207 $404,944,826 $418,732,178 $432,353,066X. TOTAL CHANGE IN CUSTOMER ELECTRIC CHARGES OR SURPLUS(9,821,745)$ (19,511,863)$ (37,641,419)$ (32,096,944)$ (24,591,584)$ (21,404,153)$ (22,649,959)$ (22,397,500)$ (22,674,951)$ (25,413,274)$ CHANGE IN CUSTOMER ELECTRIC CHARGES OR SURPLUS (%)-4%-4%-5%-4%-3%-3%-3%-3%-3%-3%183 SILICON VALLEY COMMUNITY CHOICE ENERGYFINANCIAL PRO FORMA ANALYSISSCENARIO 2CATEGORYYEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10I. CUSTOMER ACCOUNTS:RESIDENTIAL (E-1)61,781124,179 187,200 188,136 189,076190,022190,972191,927192,886193,851SMALL COMMERCIAL (A-1)5,08510,22115,40915,48615,56315,64115,71915,79815,87715,956SMALL COMMERCIAL (A-6)3326671,0061,0111,0161,0211,0261,0321,0371,042MEDIUM COMMERCIAL (A-10)7161,4392,1692,1802,1912,2022,2132,2242,2352,247LARGE COMMERCIAL (E-19)3316651,0021,0071,0121,0171,0221,0271,0321,037INDUSTRIAL (E-20)12243737373738383838STREET LIGHTING AND TRAFFIC CONTROL (LS-3)4529081,3691,3761,3831,3901,3971,4041,4111,418AGRICULTURAL (AG-1B, AG-4A, AG-4B, AG-5A, AG-5B, AG-5C)267538810814819823827831835839SUBTOTAL - CUSTOMER ACCOUNTS68,976138,642209,003210,048211,098212,153213,214214,280215,352216,428II. LOAD REQUIREMENTS (KWH):RESIDENTIAL (E-1)379,302,235 762,397,4931,149,314,221 1,155,060,792 1,160,836,096 1,166,640,276 1,172,473,478 1,178,335,845 1,184,227,524 1,190,148,662SMALL COMMERCIAL (A-1)103,830,975 208,700,259 314,615,641 316,188,719 317,769,663 319,358,511 320,955,304 322,560,080 324,172,881 325,793,745SMALL COMMERCIAL (A-6)15,589,202 31,334,295 47,236,450 47,472,633 47,709,996 47,948,546 48,188,289 48,429,230 48,671,376 48,914,733MEDIUM COMMERCIAL (A-10)161,290,281 324,193,466 488,721,650 491,165,258 493,621,084 496,089,190 498,569,636 501,062,484 503,567,796 506,085,635LARGE COMMERCIAL (E-19)226,157,453 454,576,480 685,274,044 688,700,414 692,143,916 695,604,636 699,082,659 702,578,072 706,090,963 709,621,418INDUSTRIAL (E-20)213,906,622 429,952,310 648,153,107 651,393,872 654,650,841 657,924,096 661,213,716 664,519,785 667,842,384 671,181,596STREET LIGHTING AND TRAFFIC CONTROL (LS-3)5,830,06311,718,427 17,665,529 17,753,857 17,842,626 17,931,839 18,021,498 18,111,606 18,202,164 18,293,175AGRICULTURAL (AG-1B, AG-4A, AG-4B, AG-5A, AG-5B, AG-5C)18,032,203 36,244,729 54,638,929 54,912,124 55,186,684 55,462,618 55,739,931 56,018,630 56,298,723 56,580,217SUBTOTAL - LOAD REQUIREMENTS1,123,939,035 2,259,117,460 3,405,619,571 3,422,647,669 3,439,760,907 3,456,959,711 3,474,244,510 3,491,615,733 3,509,073,811 3,526,619,180III. CCA OPERATING COSTS ($)SHORT TERM MARKET PURCHASES$4,059,363 $8,161,906$11,803,457 $11,999,206 $12,339,124 $12,774,593 $13,055,640 $13,504,281 $13,694,329 $14,012,698TERM CONTRACT PURCHASES$10,229,594 $56,571,604 $83,346,275$112,982,427 $114,610,645 $116,484,213 $134,622,855 $135,402,388 $141,841,435 $142,331,178SHORT TERM RENEWABLE MARKET PURCHASES AND RECS$35,076,103 $45,044,757 $67,963,379 $48,982,201 $56,858,919 $65,786,260 $59,197,404 $70,642,350 $75,808,294 $87,544,105SHORT TERM CARBON FREE MARKET PURCHASES$10,013,757 $23,149,763 $39,463,112 $44,779,872 $44,105,738 $43,422,383 $42,427,284 $40,997,517 $38,438,717 $35,815,942ANCILLARY SERVICES AND CAISO CHARGES$3,405,692 $7,075,827$10,997,945 $11,428,579 $11,866,795 $12,334,026 $12,821,715 $13,326,878 $13,812,781 $14,335,558RESOURCE ADEQUACY CAPACITY$5,570,842 $9,270,545$13,329,099 $13,009,335 $13,391,766 $13,788,938 $13,812,953 $14,402,178 $14,745,455 $15,381,372STAFF AND OTHER OPERATIONS COSTS$7,169,346 $8,517,394 $9,928,752$10,146,128 $10,368,322 $10,595,445 $10,827,606 $11,064,918 $11,307,498 $11,555,463BILLING AND DATA MANAGEMENT$1,622,317 $3,358,684 $5,215,112 $5,398,424 $5,588,178 $5,784,603 $5,987,931 $6,198,407 $6,416,281 $6,641,814UNCOLLECTIBLES EXPENSE$399,055 $819,072$1,223,555 $1,306,950 $1,358,967 $1,404,852 $1,463,767 $1,527,695 $1,580,324 $1,638,091STARTUP FINANCING$2,663,926 $2,663,926 $2,663,926 $2,663,926 $2,663,926$0$0$0$0$0CCA BOND CARRYING COST$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500SUBTOTAL - CCA OPERATING COSTS$80,211,494$164,634,977 $245,936,112 $262,698,547 $273,153,881 $282,376,814 $294,218,655 $307,068,112 $317,646,612 $329,257,722IV. REVENUES FROM GREEN PREMIUM AND MARKET SALES ($)GREEN PRICING PREMIUM209,086$ 432,872$ 672,130$ 695,756$ 684,201$ 670,974$ 655,973$ 639,087$ 620,204$ 599,204$ MARKET SALES$0$0$0$0$0$0$0$0$0$0V. CONTRIBUTION TO PROGRAM RESERVES ($)$3,208,460 $6,585,399 $9,837,444$10,507,942 $10,926,155 $11,295,073 $11,768,746 $12,282,724 $12,705,864 $13,170,309VI. CCA REVENUE REQUIREMENT ($)$83,210,867$170,787,505 $255,101,426 $272,510,733 $283,395,835 $293,000,912 $305,331,428 $318,711,749 $329,732,273 $341,828,827CCA PROGRAM AVERAGE RATE (CENTS/KWH)7.4 7.6 7.5 8.0 8.2 8.5 8.8 9.1 9.4 9.7 PG&E AVERAGE GENERATION COST (CENTS/KWH)9.6 9.7 10.1 10.5 10.7 10.9 11.3 11.6 11.9 12.3 VII. PG&E CCA CUSTOMER SURCHARGES ($)POWER CHARGE INDIFFERENCE ADJUSTMENT$17,176,539 $34,339,259 $57,624,201 $59,979,592 $68,846,649 $71,301,137 $73,395,868 $72,904,287 $76,084,978 $75,601,919FRANCHISE FEE SURCHARGE$807,311$1,645,165 $2,566,976 $2,677,997 $2,765,271 $2,826,865 $2,939,449 $3,028,912 $3,132,039 $3,233,921SUBTOTAL - PG&E CCA CUSTOMER SURCHARGES17,983,851$ 35,984,424$ 60,191,178$ 62,657,588$ 71,611,920$ 74,128,002$ 76,335,317$ 75,933,200$ 79,217,017$ 78,835,840$ VIII. CCA REVENUE REQUIREMENT PLUS PG&E CCA CUSTOMER SURCHARGES$101,194,718 $206,771,929 $315,292,604 $335,168,322 $355,007,755 $367,128,913 $381,666,745 $394,644,949 $408,949,290 $420,664,666IX. REVENUE AT PG&E GENERATION RATES$107,931,990 $219,947,272 $343,187,142 $358,029,788 $369,697,818 $377,932,408 $392,984,207 $404,944,826 $418,732,178 $432,353,066X. TOTAL CHANGE IN CUSTOMER ELECTRIC CHARGES OR SURPLUS(6,737,272)$ (13,175,343)$ (27,894,538)$ (22,861,466)$ (14,690,063)$ (10,803,495)$ (11,317,462)$ (10,299,877)$ (9,782,888)$ (11,688,400)$ CHANGE IN CUSTOMER ELECTRIC CHARGES OR SURPLUS (%)-3%-3%-4%-3%-2%-1%-1%-1%-1%-1%184 SILICON VALLEY COMMUNITY CHOICE ENERGYFINANCIAL PRO FORMA ANALYSISSCENARIO 3CATEGORYYEAR 1 YEAR 2 YEAR 3 YEAR 4 YEAR 5 YEAR 6 YEAR 7 YEAR 8 YEAR 9 YEAR 10I, CUSTOMER ACCOUNTS:RESIDENTIAL (E-1)61,781124,179 187,200 188,136 189,076190,022190,972191,927192,886193,851SMALL COMMERCIAL (A-1)5,08510,22115,40915,48615,56315,64115,71915,79815,87715,956SMALL COMMERCIAL (A-6)3326671,0061,0111,0161,0211,0261,0321,0371,042MEDIUM COMMERCIAL (A-10)7161,4392,1692,1802,1912,2022,2132,2242,2352,247LARGE COMMERCIAL (E-19)3316651,0021,0071,0121,0171,0221,0271,0321,037INDUSTRIAL (E-20)12243737373738383838STREET LIGHTING AND TRAFFIC CONTROL (LS-3)4529081,3691,3761,3831,3901,3971,4041,4111,418AGRICULTURAL (AG-1B, AG-4A, AG-4B, AG-5A, AG-5B, AG-5C)267538810814819823827831835839SUBTOTAL - CUSTOMER ACCOUNTS68,976138,642209,003210,048211,098212,153213,214214,280215,352216,428II. LOAD REQUIREMENTS (KWH):RESIDENTIAL (E-1)379,302,235 762,397,4931,149,314,221 1,155,060,792 1,160,836,096 1,166,640,276 1,172,473,478 1,178,335,845 1,184,227,524 1,190,148,662SMALL COMMERCIAL (A-1)103,830,975 208,700,259 314,615,641 316,188,719 317,769,663 319,358,511 320,955,304 322,560,080 324,172,881 325,793,745SMALL COMMERCIAL (A-6)15,589,202 31,334,295 47,236,450 47,472,633 47,709,996 47,948,546 48,188,289 48,429,230 48,671,376 48,914,733MEDIUM COMMERCIAL (A-10)161,290,281 324,193,466 488,721,650 491,165,258 493,621,084 496,089,190 498,569,636 501,062,484 503,567,796 506,085,635LARGE COMMERCIAL (E-19)226,157,453 454,576,480 685,274,044 688,700,414 692,143,916 695,604,636 699,082,659 702,578,072 706,090,963 709,621,418INDUSTRIAL (E-20)213,906,622 429,952,310 648,153,107 651,393,872 654,650,841 657,924,096 661,213,716 664,519,785 667,842,384 671,181,596STREET LIGHTING AND TRAFFIC CONTROL (LS-3)5,830,06311,718,427 17,665,529 17,753,857 17,842,626 17,931,839 18,021,498 18,111,606 18,202,164 18,293,175AGRICULTURAL (AG-1B, AG-4A, AG-4B, AG-5A, AG-5B, AG-5C)18,032,203 36,244,729 54,638,929 54,912,124 55,186,684 55,462,618 55,739,931 56,018,630 56,298,723 56,580,217SUBTOTAL - LOAD REQUIREMENTS1,123,939,035 2,259,117,460 3,405,619,571 3,422,647,669 3,439,760,907 3,456,959,711 3,474,244,510 3,491,615,733 3,509,073,811 3,526,619,180III. CCA OPERATING COSTS ($)SHORT TERM MARKET PURCHASES$2,138,349 $4,000,476 $4,990,457 $4,840,857 $4,751,013 $4,699,524 $4,563,852 $4,509,270 $4,357,738 $4,232,619TERM CONTRACT PURCHASES$5,388,639$46,084,798 $66,177,515 $94,943,387 $95,488,604 $96,135,040$113,223,549 $112,734,958 $118,313,226 $117,685,380SHORT TERM RENEWABLE MARKET PURCHASES AND RECS$51,926,387 $80,620,791$123,510,529 $107,698,247 $112,467,877 $118,060,841 $107,591,967 $114,483,986 $113,868,272 $119,473,820SHORT TERM CARBON FREE MARKET PURCHASES$4,929,960$12,792,213 $24,041,575 $29,030,947 $32,521,755 $36,495,558 $40,807,495 $45,397,707 $49,423,560 $54,107,821ANCILLARY SERVICES AND CAISO CHARGES$3,405,692 $7,075,827$10,997,945 $11,428,579 $11,866,795 $12,334,026 $12,821,715 $13,326,878 $13,812,781 $14,335,558RESOURCE ADEQUACY CAPACITY$5,570,842 $9,270,545$13,329,099 $13,009,335 $13,391,766 $13,788,938 $13,812,953 $14,402,178 $14,745,455 $15,381,372STAFF AND OTHER OPERATIONS COSTS$7,169,346 $8,517,394 $9,928,752$10,146,128 $10,368,322 $10,595,445 $10,827,606 $11,064,918 $11,307,498 $11,555,463BILLING AND DATA MANAGEMENT$1,622,317 $3,358,684 $5,215,112 $5,398,424 $5,588,178 $5,784,603 $5,987,931 $6,198,407 $6,416,281 $6,641,814UNCOLLECTIBLES EXPENSE$424,077 $871,923$1,304,275 $1,395,799 $1,445,541 $1,489,470 $1,548,185 $1,610,592 $1,661,224 $1,717,069STARTUP FINANCING$2,663,926 $2,663,926 $2,663,926 $2,663,926 $2,663,926$0$0$0$0$0CCA BOND CARRYING COST$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500$1,500SUBTOTAL - CCA OPERATING COSTS$85,241,036$175,258,077 $262,160,685 $280,557,129 $290,555,277 $299,384,946 $311,186,754 $323,730,394 $333,907,533 $345,132,416IV. REVENUES FROM GREEN PREMIUM AND MARKET SALES ($)GREEN PRICING PREMIUM104,543$ 216,436$ 336,065$ 347,878$ 360,106$ 372,764$ 385,866$ 399,429$ 413,469$ 428,003$ MARKET SALES$59,746$254,892 $150,425 $914,557$1,200,555 $1,580,940 $2,278,637 $2,830,291 $3,378,309 $3,990,921V. CONTRIBUTION TO PROGRAM RESERVES ($)$3,407,252 $7,000,127$10,480,410 $11,185,703 $11,574,189 $11,912,160 $12,356,325 $12,836,004 $13,221,169 $13,645,660VI. CCA REVENUE REQUIREMENT ($)$88,483,999$181,786,877 $272,154,605 $290,480,396 $300,568,806 $309,343,403 $320,878,575 $333,336,678 $343,336,924 $354,359,152CCA PROGRAM AVERAGE RATE (CENTS/KWH)7.9 8.0 8.0 8.5 8.7 8.9 9.2 9.5 9.8 10.0 PG&E AVERAGE GENERATION COST (CENTS/KWH)9.6 9.7 10.1 10.5 10.7 10.9 11.3 11.6 11.9 12.3 VII. PG&E CCA CUSTOMER SURCHARGES ($)POWER CHARGE INDIFFERENCE ADJUSTMENT$17,176,539 $34,339,259 $57,624,201 $59,979,592 $68,846,649 $71,301,137 $73,395,868 $72,904,287 $76,084,978 $75,601,919FRANCHISE FEE SURCHARGE$807,311$1,645,165 $2,566,976 $2,677,997 $2,765,271 $2,826,865 $2,939,449 $3,028,912 $3,132,039 $3,233,921SUBTOTAL - PG&E CCA CUSTOMER SURCHARGES17,983,851$ 35,984,424$ 60,191,178$ 62,657,588$ 71,611,920$ 74,128,002$ 76,335,317$ 75,933,200$ 79,217,017$ 78,835,840$ VIII. CCA REVENUE REQUIREMENT PLUS PG&E CCA CUSTOMER SURCHARGES$106,467,849 $217,771,301 $332,345,782 $353,137,985 $372,180,726 $383,471,404 $397,213,892 $409,269,878 $422,553,941 $433,194,991IX. REVENUE AT PG&E GENERATION RATES$107,931,990 $219,947,272 $343,187,142 $358,029,788 $369,697,818 $377,932,408 $392,984,207 $404,944,826 $418,732,178 $432,353,066X. TOTAL CHANGE IN CUSTOMER ELECTRIC CHARGES OR SURPLUS(1,464,141)$ (2,175,971)$ (10,841,360)$ (4,891,803)$ 2,482,908$ 5,538,996$ 4,229,685$ 4,325,052$ 3,821,763$ 841,925$ CHANGE IN CUSTOMER ELECTRIC CHARGES OR SURPLUS (%)-1%0%-2%-1%0%1%1%1%0%0%185 ORDINANCE NO. ___ . AN ORDINANCE OF THE CITY COUNCIL OF THE CITY OF SARATOGA AUTHORIZING THE IMPLEMENTATION OF A COMMUNITY CHOICE AGGREGATION (CCA) PROGRAM The City Council of the City of Saratoga does ordain as follows: SECTION 1. FINDINGS. The City Council finds as follows: 1. The Cities of Cupertino, Mountain View and Sunnyvale and the County of Santa Clara formed and sponsored the Silicon Valley Community Choice Energy Partnership (SVCCEP) to investigate options to provide electric service to customers within the City of Saratoga and surrounding municipalities with the intent of achieving greater local control and involvement over the provision of electric services, competitive electric rates, the development of local renewable energy projects, reduced greenhouse gas emissions, and the implementation of energy conservation and efficiency projects and programs. 2. The City of Saratoga, through its participation in SVCCEP, has prepared a Technical Feasibility Study for a Community Choice Aggregation (“CCA”) program under the provisions of Public Utilities Code Section 366.2. The Technical Feasibility Study shows that implementing a community choice aggregation program would likely provide multiple benefits, including the following: a. Providing customers a choice of power providers; b. Increasing local control over energy rates and other energy-related matters; c. Providing electric rates that are competitive with those provided by the incumbent utility; d. Reducing greenhouse gas emissions arising from electricity use in the City; e. Increasing local and regional renewable generation capacity; f. Increasing energy conservation and efficiency projects and programs; g. Increasing regional energy self-sufficiency; and h. Improving the local economy by implementing new local renewable and energy conservation and efficiency projects. 3. The Joint Powers Agreement creating the Silicon Valley Clean Energy Authority (“Authority”) will govern and operate the CCA program on behalf of its member jurisdictions. The Initial Participants within the County of Santa Clara, as defined by the Joint Powers Agreement, may participate in the Authority by adoption of a resolution approving the execution of the Joint Powers Agreement and adoption of the CCA ordinance required by Public Utilities Code Section 366.2(c)(12) by March 31, 2016. Municipalities choosing to participate in the Authority will have membership on the Board of Directors of the Authority as provided in the Joint Powers Agreement. 4. The Authority will enter into agreements with electric power suppliers and other service providers and, based upon those agreements, the Authority plans to provide electrical power to residents and businesses at rates that are competitive with those of the incumbent utility. Once the California Public Utilities Commission approves the implementation plan prepared by the Authority, the Authority may provide service to customers within the City of Saratoga and those cities that choose to participate in the Silicon Valley Clean Energy Authority; and 186 5. Under Public Utilities Code Section 366.2, customers have the right to opt-out of a CCA program and continue to receive service from the incumbent utility. Customers who wish to continue to receive service from the incumbent utility will be able to do so at any time; and 6. On January 20, 2016, the Saratoga City Council held a public hearing at which time interested persons had an opportunity to testify either in support or in opposition to implementation of the Silicon Valley Clean Energy CCA program in the City of Saratoga. 7. This ordinance is exempt from the requirements of the California Environmental Quality Act (CEQA) pursuant to the State CEQA Guidelines, as it is not a “project” and has no potential to result in a direct or reasonably foreseeable indirect physical change to the environment. (14 Cal. Code Regs. § 15378(a).) Further, the ordinance is exempt from CEQA as there is no possibility that the ordinance or its implementation would have a significant negative effect on the environment. (14 Cal. Code Regs.§ 15061(b)(3).) The ordinance is also categorically exempt because it is an action taken by a regulatory agency to assure the maintenance, restoration, enhancement or protection of the environment. (14 Cal. Code Regs. § 15308.) The Director of Community Development shall cause a Notice of Exemption to be filed as authorized by CEQA and the State CEQA Guidelines. SECTION 2. The above findings are true and correct. SECTION 3. AUTHORIZATION TO IMPLEMENT A COMMUNITY CHOICE AGGREGATION PROGRAM. Based upon the foregoing, and in order to provide businesses and residents within the City of Saratoga with a choice of power providers, the City of Saratoga hereby elects to implement a community choice aggregation program within the jurisdiction of the City by participating in the Community Choice Aggregation program of the Silicon Valley Clean Energy Authority, as described in its Joint Powers Agreement. SECTION 4. This Ordinance shall be in full force and effect 30 days after its adoption, and shall be published and posted as required by law. This Ordinance was introduced by the City Council of the City of Saratoga on January 20, 2016 and was adopted on February 3, 2016 by the following roll call vote: AYES: NOES: ABSENT: ABSTAIN: _____________________________________ Manny E. Cappello, Mayor ATTEST: _________________________ Crystal Bothelio, City Clerk 187 10016-0003\1907676v1.doc Final Draft (11/25/15) Silicon Valley Clean Energy Authority - Joint Powers Agreement – Effective _____________ Among The Following Parties: City of Campbell City of Cupertino City of Gilroy City of Los Altos Town of Los Altos Hills Town of Los Gatos City of Monte Sereno City of Morgan Hill City of Mountain View County of Santa Clara (Unincorporated Area) City of Saratoga City of Sunnyvale 188 -1- 10016-0003\1907676v1.doc SILICON VALLEY CLEAN ENERGY AUTHORITY JOINT POWERS AGREEMENT This Joint Powers Agreement (“Agreement”), effective as of _________, is made and entered into pursuant to the provisions of Title 1, Division 7, Chapter 5, Article 1 (Section 6500 et seq.) of the California Government Code relating to the joint exercise of powers among the parties set forth in Exhibit B (“Parties”). The term “Parties” shall also include an incorporated municipality or county added to this Agreement in accordance with Section 3.1. RECITALS 1.The Parties are either incorporated municipalities or counties sharing various powers under California law, including but not limited to the power to purchase, supply, and aggregate electricity for themselves and their inhabitants. 2.The purposes for the Initial Participants (as such term is defined in Section 2.2 below) entering into this Agreement include addressing climate change by reducing energy related greenhouse gas emissions and securing energy supply and price stability, energy efficiencies and local economic benefits. It is the intent of this Agreement to promote the development and use of a wide range of renewable energy sources and energy efficiency programs, including but not limited to solar and wind energy production. 3.The Parties desire to establish a separate public agency, known as the Silicon Valley Clean Energy Authority (“Authority”), under the provisions of the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) (“Act”) in order to collectively study, promote, develop, conduct, operate, and manage energy programs. 4.The Initial Participants have each adopted an ordinance electing to implement through the Authority a Community Choice Aggregation program pursuant to California Public Utilities Code Section 366.2 (“CCA Program”). The first priority of the Authority will be the consideration of those actions necessary to implement the CCA Program. 189 -2- 10016-0003\1907676v1.doc AGREEMENT NOW, THEREFORE, in consideration of the mutual promises, covenants, and conditions hereinafter set forth, it is agreed by and among the Parties as follows: ARTICLE 1 CONTRACT DOCUMENTS 1.1 Definitions.Capitalized terms used in the Agreement shall have the meanings specified in Exhibit A, unless the context requires otherwise. 1.2 Documents Included. This Agreement consists of this document and the following exhibits, all of which are hereby incorporated into this Agreement. Exhibit A: Definitions Exhibit B: List of the Parties Exhibit C: Annual Energy Use Exhibit D: Voting Shares Exhibit E: Funding of Initial Costs 1.3 Revision of Exhibits. The Parties agree that Exhibits B, C and D to this Agreement describe certain administrative matters that may be revised upon the approval of the Board, without such revision constituting an amendment to this Agreement, as described in Section 8.4. The Authority shall provide written notice to the Parties of the revision of any such exhibit. ARTICLE 2 FORMATION OF SILICON VALLEY CLEAN ENERGY AUTHORITY 2.1 Effective Date and Term . This Agreement shall become effective and Silicon Valley Clean Energy Authority shall exist as a separate public agency on March 31, 2016 provided that this Agreement is executed on or prior to such date by at least three Initial Participants after the adoption of the ordinances required by Public Utilities Code Section 366.2(c)(12). The Authority shall provide notice to the Parties of the Effective Date. The Authority shall continue to exist, and this Agreement shall be effective, until this Agreement is terminated in accordance with Section 7.4, subject to the rights of the Parties to withdraw from the Authority. 2.2 Initial Participants. Until March 31, 2016, all other Initial Participants may become a Party by executing this Agreement and delivering an executed copy of this Agreement and a copy of the adopted ordinance required by Public Utilities Code Section 366.2(c)(12) to the Authority. Additional conditions, described in Section 3.1, may apply (i) to either an incorporated municipality or county desiring to become a Party that is not an Initial Participant 190 -3- 10016-0003\1907676v1.doc and (ii) to Initial Participants that have not executed and delivered this Agreement within the time period described above. 2.3 Formation. There is formed as of the Effective Date a public agency named the Silicon Valley Clean Energy Authority. Pursuant to Sections 6506 and 6507 of the Act, the Authority is a public agency separate from the Parties. The debts, liabilities or obligations of the Authority shall not be debts, liabilities or obligations of the individual Parties unless the governing board of a Party agrees in writing to assume any of the debts, liabilities or obligations of the Authority. A Party who has not agreed to assume an Authority debt, liability or obligation shall not be responsible in any way for such debt, liability or obligation even if a majority of the Parties agree to assume the debt, liability or obligation of the Authority. Notwithstanding Section 8.4 of this Agreement, this Section 2.3 may not be amended unless such amendment is approved by the governing boards of all Parties. 2.4 Purpose. The purpose of this Agreement is to establish an independent public agency in order to exercise powers common to each Party and any other powers granted to the Authority under state law to study, promote, develop, conduct, operate, and manage energy and energy-related climate change programs, and to exercise all other powers necessary and incidental to accomplishing this purpose. Without limiting the generality of the foregoing, the Parties intend for this Agreement to be used as a contractual mechanism by which the Parties are authorized to participate as a group in the CCA Program pursuant to Public Utilities Code Section 366.2(c)(12). The Parties intend that subsequent agreements shall define the terms and conditions associated with the actual implementation of the CCA Program. 2.5 Powers. The Authority shall have all powers common to the Parties and such additional powers accorded to it by law. The Authority is authorized, in its own name, to exercise all powers and do all acts necessary and proper to carry out the provisions of this Agreement and fulfill its purposes, including, but not limited to, each of the following: 2.5.1 make and enter into contracts; 2.5.2 employ agents and employees, including but not limited to an Executive Director; 2.5.3 acquire, contract, manage, maintain, and operate any buildings, works or improvements; 2.5.4 acquire property by eminent domain, or otherwise, except as limited under Section 6508 of the Act, and to hold or dispose of any property; 2.5.5 lease any property; 2.5.6 sue and be sued in its own name; 2.5.7 incur debts, liabilities, and obligations, including but not limited to loans from private lending sources pursuant to its temporary borrowing powers such as Government Code Section 53850 et seq. and authority under the Act; 191 -4- 10016-0003\1907676v1.doc 2.5.8 issue revenue bonds and other forms of indebtedness; 2.5.9 apply for, accept, and receive all licenses, permits, grants, loans or other assistance from any federal, state or local public agency; 2.5.10 submit documentation and notices, register, and comply with orders, tariffs and agreements for the establishment and implementation of the CCA Program and other energy programs; 2.5.11 adopt rules, regulations, policies, bylaws and procedures governing the operation of the Authority (“Operating Rules and Regulations”); and 2.5.12 make and enter into service, energy and any other agreements necessary to plan, implement, operate and administer the CCA Program and other energy programs, including the acquisition of electric power supply and the provision of retail and regulatory support services. 2.6 Limitation on Powers. As required by Government Code Section 6509, the power of the Authority is subject to the restrictions upon the manner of exercising power possessed by the City of Cupertino and any other restrictions on exercising the powers of the Authority that may be adopted by the Board. 2.7 Compliance with Local Zoning and Building Laws. Notwithstanding any other provisions of this Agreement or state law, any facilities, buildings or structures located, constructed or caused to be constructed by the Authority within the territory of the Authority shall comply with the General Plan, zoning and building laws of the local jurisdiction within which the facilities, buildings or structures are constructed. ARTICLE 3 AUTHORITY PARTICIPATION 3.1 Addition of Parties. Subject to Section 2.2, relating to certain rights of Initial Participants, other incorporated municipalities and counties may become Parties upon (a) the adoption of a resolution by the governing body of such incorporated municipality or county requesting that the incorporated municipality or county, as the case may be, become a member of the Authority, (b) the adoption by a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section 4.9, of a resolution authorizing membership of the additional incorporated municipality or county, specifying the membership payment, if any, to be made by the additional incorporated municipality or county to reflect its pro rata share of organizational, planning and other pre-existing expenditures, and describing additional conditions, if any, associated with membership, (c) the adoption of an ordinance required by Public Utilities Code Section 366.2(c)(12) and execution of this Agreement and other necessary program agreements by the incorporated municipality or county, (d) payment of the membership fee, if any, and (e) satisfaction of any conditions established by the Board. 3.2 Continuing Participation. The Parties acknowledge that membership in the Authority may change by the addition and/or withdrawal or termination of Parties. The Parties agree to participate with such other Parties as may later be added, as described in Section 3.1. 192 -5- 10016-0003\1907676v1.doc The Parties also agree that the withdrawal or termination of a Party shall not affect this Agreement or the remaining Parties’ continuing obligations under this Agreement. ARTICLE 4 GOVERNANCE AND INTERNAL ORGANIZATION 4.1 Board of Directors. The governing body of the Authority shall be a Board of Directors (“Board”) consisting of one director for each Party appointed in accordance with Section 4.2. 4.2 Appointment and Removal of Directors. The Directors shall be appointed and may be removed as follows: 4.2.1 The governing body of each Party shall appoint and designate in writing one regular Director who shall be authorized to act for and on behalf of the Party on matters within the powers of the Authority. The governing body of each Party also shall appoint and designate in writing one alternate Director who may vote on matters when the regular Director is absent from a Board meeting. The person appointed and designated as the Director shall be a member of the governing body of the Party. The person appointed and designated as the alternate Director may be a member of the governing body of the Party, a staff member of the Party, or a member of the public. 4.2.2 The Operating Rules and Regulations, to be developed and approved by the Board in accordance with Section 2.5.11, shall specify the reasons for and process associated with the removal of an individual Director for cause. Notwithstanding the foregoing, no Party shall be deprived of its right to seat a Director on the Board and any such Party for which its Director and/or alternate Director has been removed may appoint a replacement. 4.3 Terms of Office. Each regular and alternate Director shall serve at the pleasure of the governing body of the Party that the Director represents, and may be removed as Director by such governing body at any time. If at any time a vacancy occurs on the Board, a replacement shall be appointed to fill the position of the previous Director in accordance with the provisions of Section 4.2 within 90 days of the date that such position becomes vacant. 4.4 Quorum. A majority of the Directors of the entire Board shall constitute a quorum. 4.5 Powers and Function of the Board. The Board shall conduct or authorize to be conducted all business and activities of the Authority, consistent with this Agreement, the Authority Documents, the Operating Rules and Regulations, and applicable law. 4.6 Executive Committee. The Board may establish an executive committee consisting of a smaller number of Directors. The Board may delegate to the executive committee such authority as the Board might otherwise exercise, subject to limitations placed on the 193 -6- 10016-0003\1907676v1.doc Board’s authority to delegate certain essential functions, as described in the Operating Rules and Regulations. The Board may not delegate to the Executive Committee or any other committee its authority under Section 2.5.11 to adopt and amend the Operating Rules and Regulations. 4.7 Commissions, Boards and Committees. The Board may establish any advisory commissions, boards and committees as the Board deems appropriate to assist the Board in carrying out its functions and implementing the CCA Program, other energy programs and the provisions of this Agreement. 4.8 Director Compensation. Compensation for work performed by Directors on behalf of the Authority shall be borne by the Party that appointed the Director. The Board, however, may adopt by resolution a policy relating to the reimbursement of expenses incurred by Directors. 4.9 Board Voting. 4.9.1 Percentage Vote.Except when a supermajority vote is expressly required by this Agreement or the Operating Rules and Regulations, action of the Board on all matters shall require an affirmative vote of a majority of all Directors on the entire Board. A supermajority vote is required by this Agreement for the matters addressed by Sections 3.1, 6.4, 7.1.1, 7.1.2, 7.2, and 8.4. When a supermajority vote is required by this Agreement or the Operating Rules and Regulations, action of the Board shall require an affirmative vote of the specified supermajority of all Directors on the entire Board All votes taken pursuant to this Section 4.9.1 shall be referred to as a percentage vote. No action can be taken by the Board without an affirmative percentage vote. 4.9.2 Voting Shares Vote.In addition to and immediately after an affirmative percentage vote, two or more Directors may request that, a vote of the voting shares shall be held. In such event, the corresponding voting shares (as described in Section 4.9.2 and Exhibit D) of all Directors voting in the affirmative shall exceed 50%, or such other higher voting shares percentage expressly required by this Agreement or the Operating Rules and Regulations, of all Directors on the entire Board. All votes taken pursuant to this Section 4.9.2 shall be referred to as a voting shares vote. In the event that any one Director has a voting share that equals or exceeds that which is necessary to disapprove the matter being voted on by the Board, at least one other Director shall be required to vote in the negative in order to disapprove such matter. When a voting shares vote is held, action by the Board requires both an affirmative percentage vote and an affirmative voting shares vote. 4.9.3 Voting Shares Formula.When a voting shares vote is requested by two or more Directors, voting shares of the Directors shall be determined by the following formula: 194 -7- 10016-0003\1907676v1.doc (Annual Energy Use/Total Annual Energy) multiplied by 100, where (a) “Annual Energy Use” means (i) with respect to the first two years following the Effective Date, the annual electricity usage, expressed in kilowatt hours (“kWh”), within the Party’s respective jurisdiction and (ii) with respect to the period after the second anniversary of the Effective Date, the annual electricity usage, expressed in kWh, of accounts within a Party’s respective jurisdiction that are served by the Authority and (b) “Total Annual Energy” means the sum of all Parties’ Annual Energy Use. The initial values for Annual Energy use are designated in Exhibit C and the initial voting shares are designated in Exhibit D. Both Exhibits C and D shall be adjusted annually as soon as reasonably practicable after January 1, but no later than March 1 of each year subject to the approval of the Board. 4.10 Meetings and Special Meetings of the Board. The Board shall hold at least four regular meetings per year, but the Board may provide for the holding of regular meetings at more frequent intervals. The date, hour and place of each regular meeting shall be fixed by resolution or ordinance of the Board. Regular meetings may be adjourned to another meeting time. Special meetings of the Board may be called in accordance with the provisions of California Government Code Section 54956. Directors may participate in meetings telephonically, with full voting rights, only to the extent permitted by law. All meetings of the Board shall be conducted in accordance with the provisions of the Ralph M. Brown Act (California Government Code Section 54950 et seq.). 4.11 Selection of Board Officers. 4.11.1 Chair and Vice Chair. The Directors shall select, from among themselves, a Chair, who shall be the presiding officer of all Board meetings, and a Vice Chair, who shall serve in the absence of the Chair. The term of office of the Chair and Vice Chair shall continue for one year, but there shall be no limit on the number of terms held by either the Chair or Vice Chair. The office of either the Chair or Vice Chair shall be declared vacant and a new selection shall be made if: (a) the person serving dies, resigns, or the Party that the person represents removes the person as its representative on the Board or (b) the Party that he or she represents withdraws from the Authority pursuant to the provisions of this Agreement. 4.11.2 Secretary. The Board shall appoint a Secretary, who need not be a member of the Board, who shall be responsible for keeping the minutes of all meetings of the Board and all other official records of the Authority. 4.11.3 Treasurer and Auditor. The Board shall appoint a qualified person to act as the Treasurer and a qualified person to act as the Auditor, neither of whom needs to be a member of the Board. If the Board so designates, and in accordance with the provisions of applicable law, a qualified person may hold both the office of Treasurer and the office of Auditor of the 195 -8- 10016-0003\1907676v1.doc Authority. Unless otherwise exempted from such requirement, the Authority shall cause an independent audit to be made by a certified public accountant, or public accountant, in compliance with Section 6505 of the Act. The Treasurer shall act as the depositary of the Authority and have custody of all the money of the Authority, from whatever source, and as such, shall have all of the duties and responsibilities specified in Section 6505.5 of the Act. The Board may require the Treasurer and/or Auditor to file with the Authority an official bond in an amount to be fixed by the Board, and if so requested, the Authority shall pay the cost of premiums associated with the bond. The Treasurer shall report directly to the Board and shall comply with the requirements of treasurers of incorporated municipalities. The Board may transfer the responsibilities of Treasurer to any person or entity as the law may provide at the time. The duties and obligations of the Treasurer are further specified in Article 6. ARTICLE 5 IMPLEMENTATION ACTION AND AUTHORITY DOCUMENTS 5.1 Preliminary Implementation of the CCA Program. 5.1.1 Enabling Ordinance. Prior to the execution of this Agreement, each Party shall adopt an ordinance in accordance with Public Utilities Code Section 366.2(c)(12) for the purpose of specifying that the Party intends to implement a CCA Program by and through its participation in the Authority. 5.1.2 Implementation Plan. The Authority shall cause to be prepared an Implementation Plan meeting the requirements of Public Utilities Code Section 366.2 and any applicable Public Utilities Commission regulations as soon after the Effective Date as reasonably practicable. The Implementation Plan shall not be filed with the Public Utilities Commission until it is approved by the Board in the manner provided by Section 4.9. 5.1.3 Termination of CCA Program. Nothing contained in this Article or this Agreement shall be construed to limit the discretion of the Authority to terminate the implementation or operation of the CCA Program at any time in accordance with any applicable requirements of state law. 5.2 Authority Documents. The Parties acknowledge and agree that the affairs of the Authority will be implemented through various documents duly adopted by the Board through Board resolution or minute action, including but not necessarily limited to the Operating Rules and Regulations, the annual budget, and specified plans and policies defined as the Authority Documents by this Agreement. The Parties agree to abide by and comply with the terms and conditions of all such Authority Documents that may be adopted by the Board, subject to the Parties’ right to withdraw from the Authority as described in Article 7. 196 -9- 10016-0003\1907676v1.doc ARTICLE 6 FINANCIAL PROVISIONS 6.1 Fiscal Year. The Authority’s fiscal year shall be 12 months commencing July 1 and ending June 30. The fiscal year may be changed by Board resolution. 6.2 Depository. 6.2.1 All funds of the Authority shall be held in separate accounts in the name of the Authority and not commingled with funds of any Party or any other person or entity. 6.2.2 All funds of the Authority shall be strictly and separately accounted for, and regular reports shall be rendered of all receipts and disbursements, at least quarterly during the fiscal year. The books and records of the Authority shall be open to inspection by the Parties at all reasonable times. The Board shall contract with a certified public accountant or public accountant to make an annual audit of the accounts and records of the Authority, which shall be conducted in accordance with the requirements of Section 6505 of the Act. 6.2.3 All expenditures shall be made in accordance with the approved budget and upon the approval of any officer so authorized by the Board in accordance with its Operating Rules and Regulations. The Treasurer shall draw checks or warrants or make payments by other means for claims or disbursements not within an applicable budget only upon the prior approval of the Board. 6.3 Budget and Recovery Costs. 6.3.1 Budget. The initial budget shall be approved by the Board. The Board may revise the budget from time to time through an Authority Document as may be reasonably necessary to address contingencies and unexpected expenses. All subsequent budgets of the Authority shall be prepared and approved by the Board in accordance with the Operating Rules and Regulations. 6.3.2 Funding of Initial Costs. The Initial Participants shall fund the Initial Costs of the Authority in establishing the Authority and implementing the CCA Program as described in Exhibit E to this Agreement. The Initial Participants shall remit to the Authority their respective shares of Phase 2 and 3 Initial Costs as described in Exhibit E within 30 days after the Effective Date. In the event that the CCA Program becomes operational, these Initial Costs paid by the Initial Participants shall be included in the customer charges for electric services as provided by Section 6.3.3 to the extent permitted by law, and the Initial Participants shall be reimbursed by the Authority within four years of the Effective Date. The Authority may establish a reasonable time period over which such costs are recovered. In 197 -10- 10016-0003\1907676v1.doc the event that the CCA Program does not become operational, the Initial Participants shall not be entitled to any reimbursement of the Initial Costs they have paid from the Authority or any Party. 6.3.3 CCA Program Costs. The Parties desire that, to the extent reasonably practicable, all costs incurred by the Authority that are directly or indirectly attributable to the provision of electric, conservation and energy efficiency services under the CCA Program shall be recovered through charges to CCA customers receiving such electric services or from revenues received from grants or other third-party sources. 6.3.4 Additional Contributions and Advances. Pursuant to Government Code Section 6504, the Parties may in their discretion make financial contributions, loans or advances to the Authority for the purposes of the Authority set forth in this Agreement. The repayment of such contributions, loans or advances will be on the written terms agreed to by the Party making the contribution, loan or advance and the Authority. 6.4 Debt.The Authority shall not incur any debts, including but not limited to loans and the issuance of bonds, unless approved by a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section 4.9. ARTICLE 7 WITHDRAWAL AND TERMINATION 7.1 Withdrawal. 7.1.1 General Right to Withdraw. A Party may withdraw its membership in the Authority, effective as of the beginning of the Authority’s fiscal year, by giving no less than 180 days advance written notice of its election to do so, which notice shall be given to the Authority and each Party. By a two- thirds affirmative vote of the entire Board satisfying the requirements described in Section 4.9, the Board may shorten the 180 day period for a withdrawal under this Section 7.1.1 to become effective. 7.1.2 Amendment. Notwithstanding Section 7.1.1, a Party may withdraw its membership in the Authority following an amendment to this Agreement provided that the requirements of this Section 7.1.2 are strictly followed. A Party shall be deemed to have withdrawn its membership in the Authority effective 180 days after the Board approves an amendment to this Agreement if the Director representing such Party has provided notice to the other Directors immediately preceding the Board’s vote of the Party’s intention to withdraw its membership in the Authority should the amendment be approved by the Board. By a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section 4.9, the Board may shorten the 180 day period for a withdrawal under this Section 7.1.2 to become effective. 198 -11- 10016-0003\1907676v1.doc 7.1.3 Liabilities; Further Assurances. A Party that withdraws its membership in the Authority under either Section 7.1.1 or 7.1.2 may be subject to certain liabilities, as described in Section 7.3. The withdrawing Party and the Authority shall execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, as determined by the Board, to effectuate the orderly withdrawal of such Party from membership in the Authority. The Operating Rules and Regulations shall prescribe the rights, if any, of a withdrawn Party to continue to participate in those Board discussions and decisions affecting customers of the CCA Program that reside or do business within the jurisdiction of the Party. 7.2 Involuntary Termination of a Party. This Agreement may be terminated with respect to a Party for material non-compliance with provisions of this Agreement or the Authority Documents upon a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section 4.9, including the vote and voting shares of the Party subject to possible termination. Prior to any vote to terminate this Agreement with respect to a Party, written notice of the proposed termination and the reason(s) for such termination shall be delivered to the Party whose termination is proposed at least 30 days prior to the regular Board meeting at which such matter shall first be discussed as an agenda item. The written notice of proposed termination shall specify the particular provisions of this Agreement or the Authority Documents that the Party has allegedly violated. The Party subject to possible termination shall have the opportunity at the next regular Board meeting to respond to any reasons and allegations that may be cited as a basis for termination prior to a vote regarding termination. A Party that has had its membership in the Authority terminated may be subject to certain liabilities, as described in Section 7.3. 7.3 Continuing Liability; Refund. Subject to the provisions of Section 2.3, upon a withdrawal or involuntary termination of a Party pursuant to Sections 7.1 or 7.2, the Party shall remain responsible for any claims, demands, damages, or liabilities arising from the Party’s membership in the Authority through the date of its withdrawal or involuntary termination. Notwithstanding Section 2.3, thereafter, the withdrawing or terminated Party shall be responsible for any damages, losses or costs incurred by the Authority resulting from the Party’s withdrawal, including but not limited to losses from the resale of power contracted for by the Authority to serve the Party’s load. In addition, such Party also shall be responsible for any costs or obligations associated with the Party’s participation in any program in accordance with the provisions of any agreements relating to such program provided such costs or obligations were incurred prior to the withdrawal of the Party. The Authority may withhold funds otherwise owing to the Party or may require the Party to deposit sufficient funds with the Authority, as reasonably determined by the Authority, to cover the Party’s liability for the costs described above. Any amount of the Party’s funds held on deposit with the Authority above that which is required to pay any liabilities or obligations shall be returned to the Party. 7.4 The Right to Withdraw Prior to Program Launch. After receiving bids from power suppliers for the CCA Program, the Authority must provide to the Parties a report from the electrical utility consultant retained by the Authority comparing the Authority’s total estimated electrical rates, the estimated greenhouse gas emissions rate and the amount of 199 -12- 10016-0003\1907676v1.doc estimated renewable energy to be used with that of the incumbent utility. Within 15 days after receiving this report, any Party may immediately withdraw its membership in the Authority by providing written notice of withdrawal to the Authority if the report determines that any one of the following conditions exists: (1) the Authority is unable to provide total electrical rates, as part of its baseline offering to customers, that are equal to or lower than the incumbent utility, (2) the Authority is unable to provide electricity in a manner that has a lower greenhouse gas emissions rate than the incumbent utility, or (3) the Authority will use less renewable energy than the incumbent utility. Any Party who withdraws from the Authority pursuant to this Section 7.4 shall not be entitled to any refund of the Initial Costs it has paid to the Authority prior to the date of withdrawal unless the Authority is later terminated pursuant to Section 7.5. In such event, any Initial Costs not expended by the Authority shall be returned to all Parties, including any Party that has withdrawn pursuant to this section, in proportion to the contribution that each made. Notwithstanding anything to the contrary in this Agreement, any Party who withdraws pursuant to this section shall not be responsible for any liabilities or obligations of the Authority after the date of withdrawal, including without limitation any liability arising from power purchase agreements entered into by the Authority. 7.5 Mutual Termination. This Agreement may be terminated by mutual agreement of all the Parties; provided, however, the foregoing shall not be construed as limiting the rights of a Party to withdraw its membership in the Authority, and thus terminate this Agreement with respect to such withdrawing Party, as described in Section 7.1. 7.6 Disposition of Property upon Termination of Authority. Upon termination of this Agreement as to all Parties, any surplus money or assets in possession of the Authority for use under this Agreement, after payment of all liabilities, costs, expenses, and charges incurred under this Agreement and under any Authority Documents, shall be returned to the then-existing Parties in proportion to the contributions made by each. ARTICLE 8 MISCELLANEOUS PROVISIONS 8.1 Dispute Resolution. The Parties and the Authority shall make reasonable efforts to settle all disputes arising out of or in connection with this Agreement. Before exercising any remedy provided by law, a Party or the Parties and the Authority shall engage in nonbinding mediation or arbitration in the manner agreed upon by the Party or Parties and the Authority. In the event that nonbinding mediation or arbitration is not initiated or does not result in the settlement of a dispute within 120 days after the demand for mediation or arbitration is made, any Party and the Authority may pursue any remedies provided by law. 8.2 Liability of Directors, Officers, and Employees. The Directors, officers, and employees of the Authority shall use ordinary care and reasonable diligence in the exercise of their powers and in the performance of their duties pursuant to this Agreement. No current or former Director, officer, or employee will be responsible for any act or omission by another Director, officer, or employee. The Authority shall defend, indemnify and hold harmless the individual current and former Directors, officers, and employees for any acts or omissions in the scope of their employment or duties in the manner provided by Government Code Section 995 et 200 -13- 10016-0003\1907676v1.doc seq. Nothing in this section shall be construed to limit the defenses available under the law, to the Parties, the Authority, or its Directors, officers, or employees. 8.3 Indemnification of Parties. The Authority shall acquire such insurance coverage as the Board deems necessary to protect the interests of the Authority, the Parties and the public but shall obtain no less than $2 million dollars in coverage. Such insurance coverage shall name the Parties and their respective Board or Council members, officers, agents and employees as additional insureds. The Authority shall defend, indemnify and hold harmless the Parties and each of their respective Board or Council members, officers, agents and employees, from any and all claims, losses, damages, costs, injuries and liabilities of every kind arising directly or indirectly from the conduct, activities, operations, acts, and omissions of the Authority under this Agreement. 8.4 Amendment of this Agreement. This Agreement may be amended in writing by a two-thirds affirmative vote of the entire Board satisfying the requirements described in Section 4.9. The Authority shall provide written notice to the Parties at least 30 days in advance of any proposed amendment being considered by the Board. If the proposed amendment is adopted by the Board, the Authority shall provide prompt written notice to all Parties of the effective date of such amendment along with a copy of the amendment. 8.5 Assignment. Except as otherwise expressly provided in this Agreement, the rights and duties of the Parties may not be assigned or delegated without the advance written consent of all of the other Parties, and any attempt to assign or delegate such rights or duties in contravention of this Section 8.5 shall be null and void. This Agreement shall inure to the benefit of, and be binding upon, the successors and assigns of the Parties. This Section 8.5 does not prohibit a Party from entering into an independent agreement with another agency, person, or entity regarding the financing of that Party’s contributions to the Authority, or the disposition of proceeds which that Party receives under this Agreement, so long as such independent agreement does not affect, or purport to affect, the rights and duties of the Authority or the Parties under this Agreement. 8.6 Severability. If one or more clauses, sentences, paragraphs or provisions of this Agreement shall be held to be unlawful, invalid or unenforceable, it is hereby agreed by the Parties, that the remainder of the Agreement shall not be affected thereby. Such clauses, sentences, paragraphs or provision shall be deemed reformed so as to be lawful, valid and enforced to the maximum extent possible. 8.7 Further Assurances. Each Party agrees to execute and deliver all further instruments and documents, and take any further action that may be reasonably necessary, to effectuate the purposes and intent of this Agreement. 8.8 Execution by Counterparts. This Agreement may be executed in any number of counterparts, and upon execution by all Parties, each executed counterpart shall have the same force and effect as an original instrument and as if all Parties had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another 201 -14- 10016-0003\1907676v1.doc counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. 8.9 Parties to be Served Notice. Any notice authorized or required to be given pursuant to this Agreement shall be validly given if served in writing either personally, by deposit in the United States mail, first class postage prepaid with return receipt requested, or by a recognized courier service. Notices given (a) personally or by courier service shall be conclusively deemed received at the time of delivery and receipt and (b) by mail shall be conclusively deemed given 72 hours after the deposit thereof (excluding Saturdays, Sundays and holidays) if the sender receives the return receipt. All notices shall be addressed to the office of the clerk or secretary of the Authority or Party, as the case may be, or such other person designated in writing by the Authority or Party. In addition, a duplicate copy of all notices provided pursuant to this section shall be provided to the Director and Alternate Director for each Party. Notices given to one Party shall be copied to all other Parties. Notices given to the Authority shall be copied to all Parties. ARTICLE 9 SIGNATURE IN WITNESS WHEREOF, the Parties hereto have executed this Joint Powers Agreement establishing the Silicon Valley Clean Energy Authority. By: Name: Title: Date: Party: 202 Exhibit A Page 1 10016-0003\1907676v1.doc EXHIBIT A DEFINITIONS “AB 117” means Assembly Bill 117 (Stat. 2002, ch. 838, codified at Public Utilities Code Section 366.2), which created CCA. “Act” means the Joint Exercise of Powers Act of the State of California (Government Code Section 6500 et seq.) “Agreement” means this Joint Powers Agreement. “Annual Energy Use” has the meaning given in Section 4.9.2. “Authority” means the Silicon Valley Clean Energy Authority. “Authority Document(s)” means document(s) duly adopted by the Board by resolution or motion implementing the powers, functions and activities of the Authority, including but not limited to the Operating Rules and Regulations, the annual budget, and plans and policies. “Board” means the Board of Directors of the Authority. “CCA” or “Community Choice Aggregation” means an electric service option available to cities and counties pursuant to Public Utilities Code Section 366.2. “CCA Program” means the Authority’s program relating to CCA that is principally described in Sections 2.4 and 5.1. “Days” shall mean calendar days unless otherwise specified by this Agreement. “Director” means a member of the Board of Directors representing a Party. “Effective Date” means the date on which this Agreement shall become effective and the Silicon Valley Clean Energy Authority shall exist as a separate public agency, as further described in Section 2.1. “Implementation Plan” means the plan generally described in Section 5.1.2 of this Agreement that is required under Public Utilities Code Section 366.2 to be filed with the California Public Utilities Commission for the purpose of describing a proposed CCA Program. “Initial Costs” means all costs incurred by the Authority relating to the establishment and initial operation of the Authority, such as the hiring of an Executive Director and any administrative staff, any required accounting, administrative, technical and legal services in support of the Authority’s initial activities or in support of the negotiation, preparation and approval of power purchase agreements. The Board shall determine the termination date for Initial Costs. “Initial Participants” means, for the purpose of this Agreement the County of Santa Clara, the Cities of Campbell, Cupertino, Gilroy, Los Altos, Monte Sereno, Morgan Hill, Mountain View, Saratoga, and Sunnyvale, and the Towns of Los Altos and Los Gatos. 203 Exhibit A Page 2 10016-0003\1907676v1.doc “Operating Rules and Regulations” means the rules, regulations, policies, bylaws and procedures governing the operation of the Authority. “Parties” means, collectively, the signatories to this Agreement that have satisfied the conditions in Sections 2.2 or 3.1 such that it is considered a member of the Authority. “Party” means, singularly, a signatory to this Agreement that has satisfied the conditions in Sections 2.2 or 3.1 such that it is considered a member of the Authority. “Percentage vote” means a vote taken by the Board pursuant to Section 4.9.1 that is based on each Party having one equal vote. “Total Annual Energy” has the meaning given in Section 4.9.2. “Voting shares vote” means a vote taken by the Board pursuant to Section 4.9.2 that is based on the voting shares of each Party described in Section 4.9.3 and set forth in Exhibit D to this Agreement. A voting shares vote cannot take place on a matter unless the matter first receives an affirmative percentage vote in the manner required by Section 4.9.1 and two or more Directors immediately thereafter request such vote. 204 Exhibit B Page 1 10016-0003\1907676v1.doc DRAFT EXHIBIT B LIST OF THE PARTIES (This draft exhibit is based on the assumption that all of the Initial Participants will become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to this Agreement at that time.) City of Campbell City of Cupertino City of Gilroy City of Los Altos Town of Los Altos Hills Town of Los Gatos City of Monte Sereno City of Morgan Hill City of Mountain View County of Santa Clara (Unincorporated Area) City of Saratoga City of Sunnyvale 205 Exhibit C Page 1 10016-0003\1907676v1.doc DRAFT EXHIBIT C ANNUAL ENERGY USE (This draft exhibit is based on the assumption that all of the Initial Participants will become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to this Agreement at that time.) This Exhibit C is effective as of March 31, 2016. Party Campbell Cupertino Gilroy Los Altos Los Altos Hills Los Gatos Monte Sereno Morgan Hill Mountain View Santa Clara County (Unincorporated) Saratoga Sunnyvale kWh (2014*) 208,827,224 243,359,722 296,992,863 142,219,276 42,576,999 196,007,285 7,939,338 232,520,509 664,209 ,464 397,902,304 131,604,010 1,407,826,241 *Data provided by PG&E 206 Exhibit D Page 1 10016-0003\1907676v1.doc DRAFT EXHIBIT D VOTING SHARES (This draft exhibit is based on the assumption that all of the Initial Participants will become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to this Agreement at that time.) This Exhibit D is effective as of March 31, 2016. Party Voting Share Section 4.9.2 Campbell 5.3% Cupertino 6.1% Gilroy 7.5% Los Altos 3.6% Los Altos Hills 1.1% Los Gatos 4.9% Monte Sereno 0.2% Morgan Hill 5.9% Mountain View 16.7% Santa Clara County (Unincorporated) 10.0% Saratoga 3.3% Sunnyvale 35.4% Total kWh (2014*) 208,827,224 243,359,722 296,992,863 142,219,276 42,576,999 196,007,285 7,939,338 232,520,509 664,209 ,464 397,902,304 131,604,010 1,407,826,241 3,971,985,235 100.0% *Data provided by PG&E 207 Exhibit E Page 1 10016-0003\1907676v1.doc DRAFT EXHIBIT E FUNDING OF INITIAL COSTS (This draft exhibit is based on the assumption that all of the Initial Participants will become Parties. On the Effective Date, this exhibit will be revised to reflect the Parties to this Agreement at that time.) Party Phase 1(*)Phase 2 and 3 (**)Phase 2 & 3 w/Contingency (***) Campbell --$100,000 $150,000 Cupertino $170,000 $350,000 $450,000 Gilroy --$100,000 $150,000 Los Altos --$100,000 $150,000 Los Altos Hills --$25,000 $25,000 Los Gatos --$100,000 $150,000 Monte Sereno --$25,000 $25,000 Morgan Hill --$100,000 $150,000 Mountain View $170,000 $350,000 $450,000 Santa Clara County (Unincorporated) $170,000 $350,000 $450,000 Saratoga --$100,000 $150,000 Sunnyvale $170,000 $350,000 $450,000 Total $680,000 $2,050,000 N/A -(*) Certain Parties have contributed funding prior to the Effective Date of this Agreement, as shown above under Phase 1, to conduct initial legal, technical, and administrative activities in support of the establishment of the Authority. Such activities are part of the Initial Costs described in Section 6.3 of this Agreement. -(**) Additional costs associated with program launch will be financed and thus are not covered by the Initial Cost Contributions shown here. -(***) Initial Participants are required to commit up to this amount at the time of executing the Agreement; this amount includes contingency funding should multiple Initial Participants 208 Exhibit E Page 2 10016-0003\1907676v1.doc not execute the Agreement by 3/31/16, so that the final Parties are providing sufficient contribution for Initial Costs. The Parties will be notified promptly after the Effective Date of the final Parties and contribution to Initial Costs. 209 SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:City Manager’s Office PREPARED BY:Crystal Bothelio, City Clerk/Assistant to the City Manager SUBJECT:Hazardous Vegetation Program Resolution Declaring Abatement of Public Nuisance RECOMMENDED ACTION: Conduct public hearing and adopt resolution. BACKGROUND: At the December 16, 2015 City Council meeting, the City Council approved a resolution declaring hazardous vegetation to be a public nuisance. Adoption of this resolution served as the first step in launching the annual weed abatement process conducted by the Santa Clara County Department of Agriculture’s Weed Abatement Program. The purpose of the Santa Clara County Department of Agriculture Weed Abatement Program is to prevent fire hazards posed by vegetative growth and the accumulation of combustible materials. The County Department of Agriculture provides weed abatement services to a number of cities in the County, including Saratoga. Through the program, the City is able to reduce fuel loads for fires by maintaining defensible space. Parcels in Saratoga that represent a potential hazard due to weeds or other combustible debris have been identified and listed in the attached 2016 Commencement Report, prepared and maintained by the County of Santa Clara. Following the December 16, 2015 meeting, notices were sent to owners or properties on the Commencement Report indicating that hazardous vegetation or debris has been identified on their property and hazardous materials must be abated. The notice also informed property owners of the public hearing on January 20, 2016. During the public hearing, property owners may voice objections to the listing of their property on the Commencement Report. To continue the weed abatement process, the Council should adopt the attached resolution. If approved, the County will be authorized to perform an inspection of properties on the Commencement Report to determine if properties meet Weed Abatement Program requirements. Property owners will have until April 15, 2016 to abate their property. 210 If the attached resolution is approved, a public hearing will also be set for March 16, 2016. While the City Council is only required to hold one public hearing for owners to raise objections to properties on the Commencement Report, the City Council has traditionally held two public hearings for this purpose. As with the January 20, 2016 public hearing, property owners listed in Attachment A may request that their property be removed from the Commencement Report at the March public hearing. Property owners that do not comply with minimum fire safety standards by April 15, 2015 may be subject to several different fees and the property will be scheduled for abatement by the County contractor. If abatement work is completed by a County contractor, the property owner will be assessed the contractor’s fees to perform the work plus a County fees. This year, County fees have been increased as shown below. Fees Previous Amount New Amount Initial Inspection Fee Charged annually to all parcels on the Abatement List. The fee recovers costs associated with data entry, file preparation, noticing, boundary determination, and overhead. Parcels are removed from the Weed Abatement Program after three consecutive years of compliance with weed abatement and fire standards. $41 $55 Failed Second Inspection Fee Charged for parcels that fail the second inspection or the annual compliance inspection, if the property is already on the Weed Abatement List. $250 $440 Contract Work Fee Charged to parcels where abatement work is performed by the County contractor. This fee is in addition to the contractor’s costs to abate weeds, which is charged directly to the property owner. $169 $335 Currently, there are no fiscal impacts to the City of Saratoga as a result of the Weed Abatement Program. In the past, the Santa Clara County Department of Agriculture has recovered expenses through the Weed Abatement Program fees charged to property owners. Recently, these fees have not covered the full cost of the program. In Fiscal Year 2016/17 and future years, the County is expected to transfer some of the program costs to cities that participate in the Weed Abatement Program. Resident Resources In addition to the fire prevention efforts through the Santa Clara County Weed Abatement Program, the City of Saratoga works with the Saratoga Area FireSafe Council to offer free fire prevention services to Saratoga residents. Residents in high or very high fire hazard zones in the City are eligible for free chipping of materials (such as branches or shrubs) cleared from defensible space. Additionally, the Saratoga Area FireSafe Council provides residents with information about mitigating the risk of wildfires. 2 211 The Saratoga Area FireSafe Council was established in 2013 through a partnership between the City of Saratoga, Saratoga Fire Protection District, and Santa Clara County FireSafe Council. Additional information is available at http://www.sccfiresafe.org/communities/saratoga-area. FOLLOW UP ACTION: Prior to abatement, property owners on the Abatement List will receive three notices informing them that the hazardous vegetation on their property must be abated by the owner or by the County. The notices inform the property owner that the County abatement will commence if work is not performed by the property owner. Additionally, the first two notices inform the property owner that objections to properties on the Abatement List can be made at the public hearing on January 20, 2016. The public hearing will also be noticed in the Saratoga News. ADVERTISING, NOTICING AND PUBLIC CONTACT: The County of Santa Clara mailed notices to owners of properties on the Commencement Report. Additionally, a legal advertisement announcing the public hearing was printed in the Saratoga News. ATTACHMENTS: Attachment A - Resolution Declaring Abatement of a Public Nuisance as to Specified Properties Containing Hazardous Vegetation Attachment B - 2016 Commencement Report Attachment C - Sample Informational Materials Mailed to Property Owners on Commencement Report Attachment D - Resolution 15-074 Declaring Hazardous Vegetation to be a Nuisance and Setting Public Hearing Date 212 RESOLUTION 16-___ A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SARATOGA DECLARING ABATEMENT OF A PUBLIC NUISANCE AS TO SPECIFIED PROPERTIES CONTAINING HAZARDOUS VEGETATION WHEREAS, the Saratoga City Council declared hazardous vegetation to be a public nuisance through adoption of Resolution 15-074 at the December 16, 2015 City Council Meeting; and WHEREAS, the Office of the County Agricultural Commissioner subsequently gave notice to all property owners of specific properties identified as containing hazardous vegetation (weeds) described by common name or by reference to the tract, block, lot, code area and parcel number on the report prepared by and on file in the Office of the City Clerk and of the County Agricultural Commissioner; and WHEREAS, the notice sent to owners of properties specified in Exhibit A, attached to this resolution, that the City Council would hold a public hearing on January 20, 2016 to consider any protests or objections to the declaration of a nuisance on pre-specified properties so as to require the owners of these properties to remove the hazardous vegetation or be subject to a subsequent order for abatement authorizing the County Agricultural Commissioner to perform the abatement; and WHEREAS, a public hearing on said notice was held on January 20, 2016; and WHEREAS, final action on any protests or objections to the proposed removal of weeds has been made by the City Council; NOW, THEREFORE BE IT RESOLVED, that the hazardous vegetation (weeds) on specified properties listed on Exhibit A (attached) is declared to be public nuisance and the County Agricultural Commissioner is hereby designated as the person to cause notice to be given in the manner and form provided in Saratoga City Code Section 7-15.060, and as the person to thereafter cause abatement of the seasonal and recurring hazardous vegetation (weed) nuisance as determined by resolution dated December 16, 2015, and as to specified properties as determined by this resolution. NOW, THEREFORE, BE IT FURTHER RESOLVED, that the notice specified in the preceding paragraph shall require that owners of the properties identified in Exhibit A abate the hazardous vegetative nuisance or demonstrate at a public hearing before the City Council on March 16, 2016 why the City Council should not order the County to abate such hazardous vegetation nuisance thereafter at the property owner’s expense. Attachments: Exhibit A – 2016 Weed Abatement Program Commencement Report Page 1 of 2 213 The above and foregoing resolution was passed and adopted at a regular meeting of the Saratoga City Council held on the 20th day of January 2016 by the following vote: NOES: ABSENT: ABSTAIN: ______________________________ E. Manny Cappello, Mayor ATTEST: DATE: Crystal Bothelio, City Clerk Page 2 of 2 214 2016 WEED ABATEMENT PROGRAMCOMMENCEMENT REPORTCITY OF SARATOGAEXHIBIT A14639t4651213602139820851219812178112445185971226013025I 8596I 8854187741323919t27SitusAPNWAWALN 366-06-025LN 366-06-027RD 366-14-041RD 366-31-007RD 366-32-002cER386-11-021AV 386-13-059RD 386-30-035AV 389-06-017AV 389-13-008AV 389-17-010AV 389-17-015AV 389-17-032wA 389-21-001DR 389-25-001DR 389-30-002DR 389-37-039DR 389-38-0'18DR 393-42-005RD 397-03-002RD 397-03-029BIG BASINBIG BASINBLUE HILLSARROWHEADWARDELLPROSPECTPROSPECTPASEOCOXSARATOGA-SARATOGACOXAFTONAFTONCARzuCKBONNETASPESIPORTOSMYRENDAGMARMERRICKSOBEYTEN ACRESNULLNULLANNAMALAI KADIRESAN ANDCHADHA MANDHIR AND GUPTALEE ARTHURC AND HARA DEBRA LSHIE YAW SHI AND WANG JING MAYBALLNIGEL AND PAMELAALI SYEDMONDAL SUDHRITY KAND GHOSHSUMMERHILL SARATOGA FRONTMVS COMPANY LPDOSS ROGERE TRUSTEELITVIN MIGUEL E AND ANAMARIALIU NAN AND YUAN YUANREDDING NADINE A TRUSTEETUCKER JUSTIN AND KAREN TPACIFIC GAS AND ELECTRIC COHU JINGCAO AND KAN LANYALLA SRINIVAS RAND PEDARLAMILLEREDWARD TRUSTEELUKE CHARLES AORANGI SOHYORGAN DONALD V AND KAREN M21991 SCENIC HEIGHTS WAY3969 WELLTNGTON SQ21360 BLUE HILLS LN21398 ARROWHEAD LNI0856 LINDA VISTA DR2I98I PROSPECT RD2I78I PROSPECT RD435 SERRAMONTE BLVD18597 COX AVE777 CALFORNIA AVEPO BOX 2067I8596 COX AVE18854 AFTON AVE18774 AFTON AVE13239 CARzuCK AVE19127 BONNET WAY1I I A.LMADEN BL19OIO PORTOS DR607 GRAYSON WAYl9IIO DAGMARDR2O2IO MERzuCK DR1414I SOBEY RD18843 TEN ACRES RD(-ITV/STATF',SARATOGASAN JOSESARATOGASARATOGACUPERTINOSARATOGASARATOGACOLMASARATOGAPALO ALTOSARATOGASARATOGASARATOGASARATOGASARATOGASARATOGASAN JOSESARATOGAMILPITASSARATOGASARATOGASARATOGASARATOGACACACACACACACACACACACACACACACACACACACACACACACA950709s136-t46295070-652195070-00009s014-474995070-000095070-000094014-322695070-4t07943049s07095070-410895070-465395070-465395070-460495070-521595113-200295070-51219503595070-515795070-493695070-560595070-56211901013601l9l l020210t4r4t1 884323 records oÍ 114Santa Clara County Weed Abatement ProgramPage I215 2016 WEED ABATEMENT PROGRAMCOMMENCEMENT REPORTCITY OF SARATOGAEXHIBIT ASitus APNCITY/STATE1886014478146901492314921145211441618680I 5488145811480514875145531457714961185401839415t2022060220402210022530TEN ACRESSOBEYSOBEYSOBEYSOBEYQUITOOLD WOODVESSINGEL CAMINOFRUITVALEFRUITVALEBARANGAVIA DEVIA DEVIA DEALLENDALEMONTPEREQUITOMT EDENMT EDENMT EDENMT EDENMT EDEN397-03-03B397-44-A22397-04-036397-04-126397-04-127397-05-028397-05-442397-06-030397-08-1 08397-1 7-01 0397-18-427397-18-039397-40-016397-40-417397-40-024397-43-008403-23-029410-40-018503-09-006503-09-021503-09-022503-1 0-00ô503-1 0-067SARATOGASAN DIEGOLOS GATOSSARATOGASARATOGASANTA CLARAMOLTNTAIN VIEWSARATOGASARATOGACLARKSVILLESARATOGALOS GATOSSARATOGASARATOGASARATOGASARATOGALOS 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MASSON LLCSCHULMAN STEVEN A AND SABRINA14645 BIG BASIN WAY106 HEINTZ CT20851 CANYON VIEW DR20867 CANYON VIEW DR2I27I SARATOGA HILLS RD21352 SARATOGA HILLS RD2I I5O SARATOGA HILLS RD2IO5O SARATOGA HILLS RD2I42I SARATOGA HILLS RD13845 PIKE RD4600 LITTLE APPLEGATE RD14150 DORENE CT14142 DORENE CT14134 DORENE CT21800 MT EDEN RD13957 ALBAR CT13966 ALBAR CT13935 DAMON LN13921 DAMON LN21761HEBER WAY13966 ALBARCT15055 LOS GATOS BLVD STE21243 DEEPWELL CTCACACACACACACACACACAORCACACACACACACACACACACACA92 records oÍ 114Santa Clara County \ileed Abatement ProgramPage 4218 Situs2016 WEED ABATEMENT PROGRAMCOMMENCEMENT REPORTCITY OF SARATOGAEXHIBIT A14190l3 8012t7862180021851217812199s148052t53121750211102175614930152141937015780150271s60015400RDV/ARDCTDRLNLNLNLNCTAVRDPLRDDRRDTOLL GATEPALAMINOPIERCEVIA REGINAVIA REGINAVIAREGINAVIA REGINAVIA REGINAMASSONSARATOGAVINTAGECONGRESSCONGRESSCONGRESSVINTNERBELLECOURTSARATOGA.HIDDEN CTBOHLMANBELNAPPEACH HILLNO 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EDWARD F TRUSTEEDUC DANIEL A AND LYNN KPOZOS CARYL B TRUSTEESAMPLE STEPHEN P AND PHI CHINHSLTN YLIE AND LILIARIMILLI V TRUSTEE & ET ALPELIO LINDSEY A ET AL420 SELBY LN22IO WINDING HILLS CT1380I PIERCE RD21786VIA REGINA2I8OO VIA REGINA2185I VIA REGINA2178I VIA REGINA3640 COLì-NTRY CLUB DR889 AGNEW RD21531 SARATOGA HEIGHTS21750 VINTAGE LN21770 CONGRESS HALL LN21756 CONGRESS HALL LN14I5I TEERLINK WAY14930 VINTNERCT20812 4TH ST LINIT I I4131 MACKIN WOODS LN15780 HIDDEN HILL PL15027 BOHLMAN RD15600 BELNAP DRI54OO PEACH HILL RDI4573 BIG BASIN V/AYCACACACACACACACACACACACACACACACACACACACACACA114 records o¡ 114Santa Clara County Weed Abatement ProgramPage 5219 (over) TRA 15 Notice to Destroy Weeds NOTICE IS HEREBY GIVEN that on December 16, 2015, pursuant to Article II of Chapter 6 of the Saratoga City Code, the City Council passed a resolution declaring that weeds, rubbish, refuse, obstructions or other dangerous materials as hereafter described, existing upon your property, or upon the adjacent street, constitutes a public nuisance, which must be abated by the removal and destruction thereof. NOTICE IS FURTHER GIVEN that property owners shall, without delay, remove and destroy all such weeds or brush or rubbish or other materials from their property and the abutting one-half of the street in front and alleys, if any, behinds such property and between the lot lines thereof as extended, or in front of which, said weeds are removed and such cost will constitute a lien upon such lots or lands until paid and will be collected upon the next tax roll upon which general municipal taxes are collected. All property owners having any objection to the proposed nuisance abatement are hereby notified to attend a meeting of the City Council, Council Chambers of City Hall at 13777 Fruitvale Ave., Saratoga, California, to be held on Wednesday, January 20, 2016, at 7:00 p.m., or as soon thereafter as the matter can be heard, when their objections will be heard and given due consideration. The language and format for this notice is required by California Health and Safety Code Sections 14891 Et. Seq. 220 (over) SARATOGA WEED ABATEMENT PROGRAM SCHEDULE January 20, 2016 Commencement hearing to consider objections to abatement list. April 15, 2016 PARCEL ABATEMENT DEADLINE Parcel must be free from hazardous vegetation by this date or an Inspector will order abatement. July/August 2016 Assessment Hearing to protest abatement charges. 2016 COUNTY WEED ABATEMENT FEES Properties in the Weed Abatement Program, you will be responsible for an annual inspection fee of $55.00 per parcel. Please be advised that the property owner of any parcel found to be non-compliant on or after the April 15th deadline will be charged an inspection fee of $440.00 and the property will be scheduled for abatement by the County contractor. If you complete the abatement work before the County contractor performs the abatement, you will not incur further charges. Should the abatement work be performed by a County contractor, you will be assessed the contractor’s charges plus a County administrative fee of $335.00 per parcel. 2016 COUNTY CONTRACTOR’S WEED ABATEMENT PRICE LIST A) Disc Work** PARCEL SIZE: 1st Disc + 2nd Disc = Total Discs 0-12,500 sq.ft. $202.86 $136.00 $338.86 12,501sq.ft.- 43,560sq.ft. $235.72 $170.00 $405.72 Larger than 1 Acre $100.87 $89.53 $190.40 (PER ACRE) ** It is required that parcels be disced twice a year. The cost for the first discing is higher due to additional work normally required during the first discing. B) HANDWORK $3.28 PER 100 sqft C) FLAIL 6 Foot Mower $2.28 PER 1000 sqft MOWING 12 Foot Mower $2.05 PER 1000 sqft D) LOADER WORK $110.50 PER HOUR E) DUMP TRUCK $102.00 PER HOUR F) BRUSH WORK $3.28 PER 100 sqft G) Debris removal $38.86 PER 1000sqft G) DUMP FEE 100% Added to orders with debris removal at 100% of the dump site charge. *Please note this program does not offer herbicide application as a method of abatement. 221 222 223 SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:Recreation and Facilities PREPARED BY:Michael A. Taylor, Director SUBJECT:Amendment to the Policy Pertaining to Naming City-Owned Land and Facilities RECOMMENDED ACTION: Adopt a resolution amending the City policy pertaining to the naming of City-owned land and facilities. BACKGROUND: The City Council adopted a policy pertaining to naming City-owned land and facilities on February 20, 2008 (Resolution 08-009). The policy has never been modified or updated. The City of Saratoga provides a number of its facilities for use under agreement by local non- profit organizations (NPOs). The Friends of the Library utilize the Village Library building for its Book-Go-Round, the Saratoga Historical Foundation has an agreement for use of the Museum and affiliated buildings, the Saratoga Area Senior Coordinating Council (SASCC) has the use of the Senior Center wing of the Community Center, and the Hakone Foundation operates the Hakone Gardens under contract with the City. Each of these agreements requires permission from the City prior to making any significant tenant improvements. Most of these non-profit organizations engage in fundraising activities for operations and capital improvements. As an incentive to prospective donors, many non-profit capital campaigns include “naming rights” for large contributions. As tenants of City facilities, the local NPOs listed above do not own the facilities they use and therefore are limited in their ability to name lands and facilities. The Hakone Foundation and SASCC are about to engage in significant capital fundraising projects that could substantially improve and update City facilities. Not having the authority to name the facilities they use on behalf of the City could limit their ability to raise large donations. Providing the NPO Boards with the ability to offer naming rights for large contributions may entice benefactors to donate to the organizations. Staff is recommending a minor addition to the policy (Attachment A) that would specifically allow local NPOs that have leases or use agreements for City facilities to conduct capital fund 224 drives and offer naming rights to major contributors. Council would retain the right to reject any renaming proposal. ATTACHMENTS: Attachment A – Resolution Amending Policy Pertaining to Naming City-Owned Land & Facilities 2 225 RESOLUTION NO. _________ RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SARATOGA AMENDING THE POLICY PERTAINING TO NAMING CITY-OWNED LAND AND FACILITIES WHEREAS, the City Council of the City of Saratoga adopted the Policy Pertaining to Naming City-Owned Land and Facilities on February 20, 2008 via Resolution 08-009; and WHEREAS, the City Council adopted the policy to establish criteria and procedures for the naming and renaming of City-owned land, facilities and portion of facilities (e.g. rooms, fields, etc.); and WHEREAS, the policy would pertain to all City-owned lands, facilities and portions of facilities with the exception of City streets, which is managed by the City’s Community Development Department under a separate set of policies and procedures; and WHEREAS, the City Council wishes to amend the policy to provide local non-profit organizations using City-owned facilities or parks operated under agreement with the City with the opportunity to offer naming rights to major donors; NOW, THEREFORE, BE IT RESOLVED that the City Council of the City of Saratoga does hereby amend the policy pertaining to Naming City-owned Land and Facilities (attached). The above and foregoing resolution was passed and adopted at a regular meeting of the Saratoga City Council held on the 20th day of January 2016 by the following vote: NOES: ABSENT: ABSTAIN: E. Manny Cappello, Mayor ATTEST: DATE: Crystal Bothelio, City Clerk Adopted Via Resolution 16 -__, January 20, 2016 226 NAMING CITY-OWNED LAND AND FACILITIES I.PURPOSE The intent of this policy is to establish criteria and procedures for the naming and renaming of City-owned land and facilities. II.OVERVIEW 1.This policy provides a mechanism for citizens to suggest names they believe should be considered for new City facilities, lands and/or portions of facilities (e.g. rooms, fields, etc.) and for the renaming of existing facilities, lands and/or portions of facilities (e.g. rooms, fields, etc.). 2.This policy pertains to all City-owned lands and facilities with the exception of City streets. The naming of streets is managed by the City’s Community Development Department under a separate set of policies and procedures. III.GENERAL POLICIES 1.The City Council shall have the authority to name and rename City-owned lands and facilities. NOTE:The City has a separate “Tree and Bench Dedication” Program. Information about this program can be found on the City’s website at http://www.saratoga.ca.us/pdf/treebenchapplication1.pdf, or by contacting the City Clerk. 2.The donation of land(s), facility(ies), or funds for the acquisition, renovation or maintenance of land(s) or facilities, shall not constitute an obligation by the City to name the land(s) and/or facility(ies) or any portion thereof after an individual, family or organization. 3.The cost of plaques, monuments and/or replacement of signs resulting from naming or renaming of City-owned facilities, lands and/or portions of facilities will be borne by the individual, group or organization sponsoring the request. An exception to this policy may be made by the City Council in the case of economic hardship and if there are City funds available to cover the costs. IV.NAMING CRITERIA 1.The following criteria shall be used in selecting an appropriate name for City-owned lands and facilities: a.The name should, if possible, include or preserve the geographic, environmental (relating to natural or physical features), historic or landmark connotation of particular significance to the area in which the land or facility is located, or for the City as a whole. Either connotation is equally valid. b.Consideration may be given to naming a City-owned land or facility after an individual, family or organization when the land, facility, or the money for its purchase, construction, renovation or maintenance was donated by the individual, family or organization. Adopted Via Resolution 16 -__, January 20, 2016 227 c.City-owned land or facilities operated under agreement by a local non-profit organization may offer naming rights to major donor(s) as enticement to receive capital project contributions, however the City Council retains the right to reject any renaming proposal. d.Consideration may also be given to naming a City-owned land or facility after an individual, family or organization when warranted by some in-kind contribution or service which is deemed to be of major and lasting significance to the purchase of the piece of land, facility, or the planning, development, construction, renovation or maintenance of a facility. e.City-owned land(s) and/or park(s) may be named for benefactor organizations, groups or businesses. f.City-owned land(s) or facility(ies) may not be named after a seated elected or appointed official. g.City-owned land(s) or facility(ies) may be named after an employee, or former employee of the City of Saratoga if three (3) or more of the following criteria are met: The employee’s contributions were over and above the normal duties required by his/her job; The employee had a positive impact on the past and future development of programs or facilities in the City of Saratoga; The employee made significant volunteer contributions to the community outside the scope of his/her job; The employee had exceptionally long tenure with the City of Saratoga (i.e. over 25 years); There is significant public support for a memorial to the employee on the occasion of his/her death or retirement. V.POLICY & CRITERIA REGARDING RENAMING 1.Existing place names are deemed to have historic recognition. City policy is to retain the name of any existing land(s) and/or facility(ies) particularly when the name has City or regional significance. The City Council may consider renaming the facility if there are compelling reasons to do so, including, but not limited to when a facility has reached the end of its normal lifespan. a.City-owned land or facilities operated under agreement by a local non-profit organization may offer renaming rights to major donor(s) as enticement to receive capital project contributions, however the City Council retains the right to reject any renaming proposal. 2.The following criteria shall be used in renaming City-owned lands and facilities: a.The individual, family or organization has made lasting and significant contributions to the protection of natural or cultural resources of the City; or b.The individual, family or organization has made substantial contributions to the betterment of a specific facility or park consistent with the established standards for the facility; or c.The individual, family or organization has made substantial contributions to the advancement of commensurate types of recreational opportunities within the City. Adopted Via Resolution 16 -__, January 20, 2016 228 VI.PROCEDURE FOR NAMING & RENAMING OF CITY-OWNED LAND(S) OR FACILITY(IES) 1.A request to name or rename a City-owned land or facility shall be made in writing on the standard application form attached to this policy. 2.The application will be reviewed for completeness by staff in the City’s Recreation (and Facilities) Department and forwarded to the Mayor. 3.The Mayor will designate an appropriate City Commission to review the application and make a recommendation to the City Council. 4.The City Council shall have final approval of naming and renaming recommendations. Adopted Via Resolution 16 -__, January 20, 2016 229 CITY OF SARATOGA APPLICATION FOR NAMING OR RENAMING CITY-OWNED LAND(S) OR FACILITY(IES) Applicant’s Contact Information: Name: Address: E-mail: Phone: Naming/ Renaming Information for City-owned Land or Facility: Suggested Name: Location of Site or Facility: Is the proposed name for only a portion of the site or facility? Yes  No If yes, please indicate portion suggested for naming/ renaming: To name or rename a City-owned site or facility, certain criteria must be met. Please indicate below which criteria will be met for the proposed name: Sites or Facilities that DO NOT Currently Have a Name Criteria for naming (please check all that apply): The name preserves the geographic, environmental (relating to natural or physical features), historic or landmark connotation of particular significance to the area in which the land or facility is located, or for the City as a whole. The land, facility, or the money for its purchase, construction, renovation or maintenance was donated by the individual, family or organization. An in-kind contribution or service of major and lasting significance was made to the acquisition of the land, facility, or the planning, development, construction, renovation or maintenance of a facility. The name recognizes a benefactor organization, group or business that contributed to the site or facility. The name recognizes a current or former employee who has: (check at least 3 criteria below) Made contributions over and above the normal duties required by his/her job; Had a positive impact on the past and future development of programs or facilities in the Adopted Via Resolution 16 -__, January 20, 2016 230 City of Saratoga; Made significant volunteer contributions to the community outside the scope of his/her job; Had exceptionally long tenure with the City of Saratoga (i.e. over 25 years); Significant public support for a memorial to the employee on the occasion of his/her death or retirement. Sites or Facilities that Currently Have a Name Criteria for naming (please check all that apply): The individual, family or organization has made lasting and significant contributions to the protection of natural or cultural resources of the City. The individual, family or organization has made substantial contributions to the betterment of a specific facility or park consistent with the established standards for the facility. The individual, family or organization has made substantial contributions to the advancement of commensurate types of recreational opportunities within the City. For all facilities, please provide a detailed explanation that supports the criteria for which you are requesting naming or renaming of the site or facility for this individual, family or organization: (If needed, please attach additional pages in order to provide a thorough discussion of the merits of your request.) PLEASE NOTE: Adopted Via Resolution 16 -__, January 20, 2016 231 1.The City Council may consider renaming a facility if there are compelling reasons to do so, including, but not limited to when a facility has reached the end of its normal lifespan. 2.The cost of plaques, monuments and/or replacement of signs resulting from naming or renaming of City-owned facilities, lands and/or portions of facilities will be borne by the individual, group or organization sponsoring the request. An exception to this policy may be made by the City Council in the case of economic hardship and if there are City funds available to cover the costs. City of Saratoga Use Only: Date Received:_____________________________ Date Scheduled for Review by Commission:_____________________________ Adopted Via Resolution 16 -__, January 20, 2016 232 SARATOGA CITY COUNCIL MEETING DATE:January 20, 2016 DEPARTMENT:City Manager’s Office PREPARED BY:Crystal Bothelio, City Clerk/Assistant to the City Manager SUBJECT:Resolution Calling for a Collaborative Solution to Homelessness in Santa Clara County RECOMMENDED ACTION: Adopt resolution finding that homelessness is a regional crisis and calling for a collaborative solution in Santa Clara County. BACKGROUND: In December 2015, the Cities Association of Santa Clara County submitted letters to each city in the County requesting Council adoption a resolution in support of regional coordination of efforts to address homelessness in the County. Consequently, Mayor Cappello placed this item on the January 20, 2016 agenda for City Council consideration. The attached resolution reflects efforts that the City of Saratoga has already undertaken to help address the problem of homelessness. This includes efforts to encourage secondary units and provide for supportive housing. Additionally, the resolution notes the City of Saratoga’s participation in the Countywide nexus study to evaluate the feasibility of an affordable housing impact fee. ATTACHMENTS: Attachment A – Resolution Finding that Homelessness is a Regional Crisis in Santa Clara County and Calling for a Collaborative Solution Attachment B – Letter and Sample Resolution from the Cities Association of Santa Clara County 233 RESOLUTION NO. 16-_____ A RESOLUTION OF THE CITY COUNCIL OF THE CITY OF SARATOGA FINDING THAT HOMELESNESS IS A REGIONAL CRISIS IN SANTA CLARA COUNTY & URGING JURISDICTIONS IN THE COUNTY TO SEEK A COLLABORATIVE SOLUTION WHEREAS, the 2015 Santa Clara County Point-In-Time Homeless Census and Survey found that there are 6,556 homeless individuals in Santa Clara County; and WHEREAS, the Homeless Census and Survey revealed that 39% of homeless individuals in Santa Clara County suffer from psychiatric or emotional conditions, 38% struggle with drug or alcohol abuse, 30% have a physical disability, 25% suffer from post-traumatic stress disorder, 22% have chronic health problems, and 63% have been homeless for one year or more; and WHEREAS, the New England Journal of Medicine published research that stated that the average life expectancy for homeless individuals is 25 years less than those in stable housing; and WHEREAS, the San Jose Mercury News reported in August 2015 that the average monthly rent in Santa Clara County is $2,552, making Santa Clara Valley one of the most expensive rental markets in the United States; and WHEREAS, Destination Home’s Community Plan to End Homelessness in Santa Clara County calls for a “Housing First” model that “centers on providing people experiencing homelessness with housing as quickly as possible; and WHEREAS, the Homeless Census and Survey found that 93% of homeless people surveyed answered “Yes” when asked if they would want affordable permanent housing, were it available; and WHEREAS, the City of Saratoga wishes to be part of regional effort to end homelessness in Santa Clara County and has adopted a number of goals intended to address issues associated with homelessness. NOW, THEREFORE BE IT RESOLVED, that the City Council of the City of Saratoga does hereby recognize that homelessness in Santa Clara County constitutes a crisis that requires a response from jurisdictions across Santa Clara Valley and seeks to be part of regional solution to the problem of homelessness through the following efforts: 1.The solution to the problem of homelessness is to provide homeless individuals with permanent affordable housing or supportive housing, which will require jurisdictions in the county to raise funds to construct sufficient housing in the region for the homeless population in Santa Clara County. In October 2015, the Saratoga City Council authorized participation in a Countywide nexus study to evaluate feasibility of establishing an affordable housing impact fee to raise funds to improve the County’s regional affordable housing supply. 2.For many years, the City of Saratoga has allowed secondary dwelling units. As part of the Page 1 of 2 234 City of Saratoga’s 2015-2023 General Plan Housing Element, the City Council adopted an ordinance to encourage secondary dwelling units by broadening criteria for secondary dwelling units and making these units easier to build through incentives, such as reduced fees and Floor Area Ratio incentives. Additional secondary dwelling units will help to increase the number of affordable housing units in Saratoga 3.The City of Saratoga’s has made it easier to establish transitional and supportive housing, which often provides housing to individuals who are at risk of becoming homeless. The above and foregoing resolution was passed and adopted at a regular meeting of the Saratoga City Council held on the 20th day of January 2016 by the following vote: NOES: ABSENT: ABSTAIN: E. Manny Cappello, Mayor ATTEST: DATE: Crystal Bothelio, City Clerk Page 2 of 2 235 P.O. Box 1079 Los Gatos, CA 95031 408-766-9534 www.CitiesAssociation.org December 11, 2015 Dear Mayor Manny Cappello and City Manager James Lindsay: On behalf of the Cities Association of Santa Clara County, we request your support in regional coordination towards addressing homelessness and the housing needs of our communities. Homelessness impacts all of our cities; over 6,000 people are homeless across the county on any given night. The average rent is $2,623 and the average home price exceeds $1 million. Earlier this year, our Board adopted Homelessness and Affordable Housing as priorities for 2015 with the mutual understanding that regional/governance coordination is needed in order to maximize resources, identify a permanent source of funding for affordable housing, and reduce homelessness across our region. Cities Association President Jason Baker had the honor of representing the Association on Supervisor Cortese’s Housing & Homelessness Task Force this past year. Together with community leaders and stakeholders including SCC Supervisors Mike Wasserman and Cindy Chavez, SJ/SV Chamber of Commerce CEO Matt Mahood, South Bay Labor Council Executive Officer Ben Field, San Jose Council Member Don Rocha, Housing Trust Silicon Valley CEO Kevin Zwick, and State Senator Jim Beall, they focused on developing interim and permanent housing units, a system of care, and long-‐term housing policy. The Task Force’s valuable work led to a Resolution declaring homelessness a crisis and a call for jurisdictions to consider a menu of strategies for agencies to implement within their communities in order to provide affordable housing and reduce homelessness. We request that the City of Saratoga bring forward the attached Resolution before its council for adoption. The Cities Association in November and the County’s Housing Task Force in October of 2015 each unanimously adopted the Resolution. The Cities Association values the Resolution as a tool that provides a regional framework and ensures countywide actions are coordinated and continue throughout the region within our communities. We understand each city is unique, with varying resources, and may opt for a different combination of the tools listed in the Resolution. Each agency can play a role in preventing homelessness and increasing the supply of affordable and supportive housing. By passing the Resolution, you will join neighboring cities and the County in expressing a commitment to work collaboratively across the region. Thank you for your consideration, Jason Baker President 2015 Cities Association of Santa Clara County Raania Mohsen Executive Director Cities Association of Santa Clara County 236 ' RESOLUTION OF THE HOUSING TASK F'ORCE OF THE COT,NITY OF SANTA CLARÄ FINDING THAT THE PROBLEM OF HCIMELESSNESS tN SANTA CLARA COUNTY CONSTITUTES A CRTSIS AND URGING JURISDICTIONS \ryITIIIN THE COUNTY TO CONSIDER POLICY OPTIONS FOR FUNDING AFFORDABLE HOUSING FOR THE PURPOSE OF HOUSING THE HOMELESS \ryHERIAS, the Santa Clara County Board of Supervisors, at the recommendation of Supervisor Dave Cortese, created the Housing-Task Force for the purpose of idonti$ing solutions to the immediate housing needs of homeless families and individuals across Santa Cla¡a County; and' WHEREAS, the 2015 Santa Clara CountyPoinþIn-Tirne Homeless Census & Suvey found that there are 6,556 homeless persons livíng within the County, and that 63% of them have been homeless for one year or more; and WBERßAS, the U.S. Deparhnent of Housing and Urban Developmeht's 2014 Annual Homeless Assessment R.eport found that, among the 48 Major City Continuums of Ca¡e in the United States, Santa Clara County has the third largeet number of chroníc¿lly homeloss poreons, the fourth largest number of homeless individuals, thq fourilr largest number of unaccompaniod homeless youth zurd the fifth largest number of homcless veterans; and \ryHEREÁ.S, the Homcless Census & Survey found that39% of horneless individuals within the County suffer from psychiatric or emotional conditions, 38% struggle with drug or aicohol abusq 30% have a physical disabilíty, 257o suffer ûom post-haumatic stress disorder, Z2Yohave chronic health problems, and 630/o have beEn homeless for one year or more; and WHEREAS, according to research published in the New England Journal ofMedicinq the average life expectanoy for indivíduals exporiencing homelessness is 25 years less than those in statle housing¡ and WHDREAS, tþe 2015 Home Not Found rtoAy revealed that, of the 511 homeless peopie within the srudy's survey population who diçd betwçen 2007,and 2A12,54% of them died outsido of a hospital or other institutional sçtting, which means that they died "quite possibly on the street;" and WHEREAS, the Homç Not Fourtd study also demonstrated that the cost of proViding servioes to homsless residents, inoluding seruices in the health care and criminal justice systerns, averaged $qZO mittion per year over the six-year study period, or $3.1 billion over the entire period; and WEEREAS, in addition to impacting the lives of homeless rcsidents, homelessuess also poses challenges for resiäents and businesses located ne-ar homeless encampments; and Rosolution of the llousing Task Force Of the County of Santa Cl¡ra Revisod based on motfon st l0/09/1t Housing Task Forcê Mtg, Page 1 ofS 237 WHEREAS, in August 2015, the San Jose Mercury News reported that the average monthly rent in Santa Clara County had reached $2,552, making it one of the most expensive rental markets in the nation; and WHEREAS, the 2A1.4-202A Regional Housing Needs Allocation identifies the need for 9,542 new Low Income units and 16,158 Very Low lncome units within Santa Clara County; and \ryHEREAS, Destination: Home's Community Plan to End Homelessness in Santa Clarc County relies upon the "Housing First" model, which "centers on providing people experiencing homelessness with housing as quickly as possible;" and WHEREAS, the Affordable Housing Funding Landscape & Best Practices white paper found that due to the dissolution of redevelopment agencies in California and cuts to federal programs, affordable housing funding in Santa Clara County decreased from $126 million in 2008 to $47 million in 2013; and \ryHEREAS, the Homeless Census & Survey found that93% of homeless people suweyed answered "Yes" when asked if they would want affordable permanent housing, were it available. NO\ry, THEREFORE, BE IT RESOLVED BY THE HOUSING TASK FORCE OF THE COT]NTY OF SANTA CLARA: 1. The problem of homelessness in Santa Clara County constitutes a crisis. It imposes unacceptable costs, both in terms ofpublic resources and human suffering, and requires an urgent response from public officials aoross Santa Clara County. 2. The solution to the problem of homelessness is to provide homeless individuals with permanent affordable housing or supportive housing. Construction of an adequate supply of affordable housing will require the creation of new local funding sources, These funding efforts will be most successfrrl if implemented consistently across all of the County's fifteen cities. 3. In the interest of promoting a consistent approaoh to affordable housing funding in Santa Clara County, the Housing Task Force recoûlmends that all cities in the County (and other jurisdictions, where applicable) conduct their own analysis of the following measures for funding affordable housing, and formally consider whether to adopt them: a. Inolusionary Zorung* Inclusionary zoning requires that developers include a percentage of below market rate units for low to moderate income households in new market-rate, for-sale residential developments. b. Affordable Housing Impact Fees - Impact fees are charged to developers to mitigate the projected impacts of new market-rate devolopments on the need for affordable housing. The first step for jurisdictions considering an impact fee is Resolution of the Housing Task Force Page 2 of 5 Of the County of Sant¿ Clara Revised based on motion at 10/09115 Housing Task Force Mtg, 238 Resolution of the Housing Task Force Of the County of Santa Clara often to conduct a nexus study to quantify the impact of new development on housing need. There are two types of impact fees: i. Residential lmpact Fees are assessed on new rental or for-sale housiirg development. ii. Commercial Linkage Fees are assessed on new commercial or industrial developmcnt. c. Batlot Initiatives - Local jurisdictions have the ability to place tax measures on the ballot for voter approval. As jurisdictions consider whether to place tax measures on the ballot for the 2016 election cycle, they shotrld consider includittg funding for affordable housing within their measures. d. Surplus Land - The Count¡ Cities, and other jurisdictions have the ability to prioritize surplus land owned by the jurisdiction for affordable housing äevelopment, thereby faoilitating affordability by reducing or eliminating land costs. e. ZoungActions * Cities can take various zoning actions to encourage procluction of both deed-restricted affordable housing and "naturally'' affordable housing, including: i. Adoption of a second unit ordinance that enables homeowners to build secondary residential structures on existing lots. ii. Allowing the construction of micro-units of 200-400 square feet that are relatively more affordable than other market rate units. iii. Protecting naturally affordable existing housing, such as mobile home parks. Cities cân govem the conversion of mobile home parks tluough polic¡ ordinance, or their general plans. hr the event parks do convert, ãities can adopt replacement housing provisions that would require that displaced intrãUitants be fairly compensated, that replacement housing be made available to displaced residents and that an affordable housing component be required as part of the development plan for the converted site. iv. Incentivizing affordable housing by offering zoning benefits, such as increasedìensity or height or decreased parking requirements, to make the production of affordable housing more economically viable. f. Boomerang Funds * Boomerang funds are former Redevelopment Agency funds that return io the County, cities and other local jurisdictions. Cities should consider whether to commit 20o/o af thøír ongoing boomerang funds to affordable Revised based on motion at 10/09/15 Housing TaskForce Mtg' Page 3 of5 239 housing, to partially make up for the affordable housing funding lost with the dissolution of redevelopment agencies. g. Adopt Community Plan to End Homelessness. All cities within the County that have not yet enacted the regional Community Plan to End Homelessness should fonnally adopt the Plan. h. If the above measures are not sufficient to end homelessness' even when frrlly implemented, and no new permanent source of funding for affordable housing is forthcoming from the State, local jurisdictions could consicler additional measures that may be needed to solve the problem, such as a ballot measure solely dedicated to establishing apermanent source of funding for affordable housing. il l/ lt // ll il /t // // /l t/ il lt il /t l/ /t Resolution of the Housing Task Force Of the County of Santa Clara Revised based on motion at l0l09ll5 Housing Task Force Mtg. Page 4 of5 240 4. The Housing Task Force requests that all cities in Santa Clara County, the Santa Clara County Cities Association, other involved govefirmental jurisdictions, and other organizations participating in the work of the Task Force bring this resolútion before their governing boards for adoption, thereby joining together to acknowledge the crisis of homelessness and pursue consideration of the above strategies, with the goal of ending homelessness in Santa Clara County. PASSED AND ADOPTED by the Housing Task Force of the County of Santa Clua, State of California, on October 9,2A15, by the following vote: AYES: BAKER, BEALL, CHAVEZ, FIELD, GUERRA, HARASZ, MAHOOD, ROCHA, WALKER, WASSERMAN, ZVIICK. NOES: NONE ABSENT: NONE ABSTAIN: NONE BBN Housing Task Fqrce of the County of Santa Clara MATT MAHOOD, Co-Chairperson Housing Tdsk Force of the County of Santa Clara ATTEST MEGAN Clerk of the Board of Supervisors APPROVED AS TO FORM AND LEGALITY: P. KORB Counsel Resolution of the Housing Task Forcc Of the Counry of Santa Clara Revised bassd on motion at 10i09/15 Housing Task Force Mtg. Page 5 of5 241